Notices. Final rule
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BILLING CODE 8320-01-M 72 83 Tuesday, May 1, 2007 Rules and Regulations Part II Environmental Protection Agency 40 CFR Part 80 Regulation of Fuels and Fuel Additives: Renewable Fuel Standard Program; Final Rule ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 80 [EPA-HQ-OAR-2005-0161; FRL-8299-9] RIN 2060-AN76 Regulation of Fuels and Fuel Additives: Renewable Fuel Standard Program AGENCY: Environmental Protection Agency (EPA). ACTION: Final rule. SUMMARY: Under the Clean Air Act, as amended by Section 1501 of the Energy Policy Act of 2005, the Environmental Protection Agency is required to promulgate regulations implementing a renewable fuel program.
The statute specifies the total volume of renewable fuel that the regulations must ensure is used in gasoline sold in the U.S. each year, with the total volume increasing over time. In this context, this program is expected to reduce dependence on foreign sources of petroleum, increase domestic sources of energy, and help transition to alternatives to petroleum in the transportation sector. The increased use of renewable fuels such as ethanol and biodiesel is also expected to have the added effect of providing an expanded market for agricultural products such as corn and soybeans.
Based on our analysis, we believe that the expanded use of renewable fuels will provide reductions in carbon dioxide emissions that have been implicated in climate change. Also, there will be some reductions in air toxics emissions such as benzene from the transportation sector, while some other emissions such as oxides of nitrogen are expected to increase. This action finalizes regulations designed to ensure that refiners, blenders, and importers of gasoline will use enough renewable fuel each year so that the total volume requirements of the Energy Policy Act are met.
Our rule describes the standard that will apply to these parties and the renewable fuels that qualify for compliance. The regulations also establish a trading program that will be an integral aspect of the overall program, allowing renewable fuels to be used where they are most economical while providing a flexible means for obligated parties to comply with the standard. DATES: This final rule is effective on September 1, 2007. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of September 1, 2007.
ADDRESSES: EPA has established a docket for this action under Docket ID No. EPA-HQ-OAR-2005-0161. All documents in the docket are listed in the *www.regulations.gov* Web site. Although listed in the index, some information is not publicly available, e.g., confidential business information
(CBI)or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically through *www.regulations.gov* or in hard copy at the EPA Docket Center, EPA/DC, EPA West, Room 3334, 1301 Constitution Ave., NW., Washington, DC. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is
(202)566-1744 and the telephone number for the EPA Docket Center is
(202)566-1742. FOR FURTHER INFORMATION CONTACT: Julia MacAllister, U.S. Environmental Protection Agency, National Vehicle and Fuel Emissions Laboratory, 2000 Traverwood, Ann Arbor MI, 48105; telephone number
(734)214-4131; fax number
(734)214-4816; e-mail address *macallister.julia@epa.gov.* SUPPLEMENTARY INFORMATION: I. General Information Entities potentially affected by this action include those involved with the production, distribution and sale of gasoline motor fuel or renewable fuels such as ethanol and biodiesel. Regulated categories and entities could include: Category NAICS 1 codes SIC 2 codes Examples of potentially regulated entities Industry 324110 2911 Petroleum Refineries. Industry 325193 2869 Ethyl alcohol manufacturing. Industry 325199 2869 Other basic organic chemical manufacturing. Industry 424690 5169 Chemical and allied products merchant wholesalers. Industry 424710 5171 Petroleum bulk stations and terminals. Industry 424720 5172 Petroleum and petroleum products merchant wholesalers. Industry 454319 5989 Other fuel dealers. 1 North American Industry Classification System (NAICS). 2 Standard Industrial Classification
(SIC)system code. This table is not intended to be exhaustive, but provides a guide for readers regarding entities likely to be regulated by this action. This table lists the types of entities that EPA is now aware could potentially be affected by this action. Other types of entities not listed in the table could also be affected. To decide whether your organization might be affected by this action, you should carefully examine today's notice and the existing regulations in 40 CFR part 80. If you have any questions regarding the applicability of this action to a particular entity, consult the persons listed in the preceding FOR FURTHER INFORMATION CONTACT section. Table of Contents I. Introduction A. The Role of Renewable Fuels in the Transportation Sector B. Requirements in the Energy Policy Act C. Development of the RFS Program II. Overview of the Program A. Impacts of Increased Reliance on Renewable Fuels 1. Renewable Fuel Volume Scenarios Analyzed 2. Emissions 3. Economic Impacts 4. Greenhouse Gases and Fossil Fuel Consumption 5. Post 2012 RFS Standards B. Program Structure 1. What Is the RFS Program Standard? 2. Who Must Meet the Standard? 3. What Qualifies as a Renewable Fuel? 4. Equivalence Values of Different Renewables Fuels 5. How Will Compliance Be Determined? 6. How Will the Trading Program Work? 7. How Will the Program Be Enforced? C. Voluntary Green Labeling Program III. Complying With the Renewable Fuel Standard A. What Is the Standard That Must Be Met? 1. How Is the Percentage Standard Calculated? 2. What Are the Applicable Standards? 3. Compliance in 2007 4. Renewable Volume Obligations B. What Counts as a Renewable Fuel in the RFS Program? 1. What Is a Renewable Fuel That Can Be Used for Compliance? a. Ethanol Made From a Cellulosic Feedstock b. Ethanol Made From any Feedstock in Facilities Using Waste Material To Displace 90 Percent of Normal Fossil Fuel Use c. Ethanol That Is Made From the Non-Cellulosic Portions of Animal, Other Waste, and Municipal Waste d. Foreign Producers of Cellulosic and Waste-Derived Ethanol 2. What Is Biodiesel? a. Biodiesel (Mono-Alkyl Esters) b. Non-Ester Renewable Diesel 3. Does Renewable Fuel Include Motor Fuel That Is Made From Coprocessing a Renewable Feedstock With Fossil Fuels? a. Definition of “Renewable Crudes” and “Renewable Crude-Based Fuels” b. How Are Renewable Crude-Based Fuel Volumes Measured? 4. What Are “Equivalence Values” for Renewable Fuel? a. Authority Under the Act To Establish Equivalence Values b. Energy Content and Renewable Content as the Basis for Equivalence Values c. Lifecycle Analyses as the Basis for Equivalence Values C. What Gasoline Is Used To Calculate the Renewable Fuel Obligation and Who Is Required To Meet the Obligation? 1. What Gasoline Is Used To Calculate the Volume of Renewable Fuel Required To Meet a Party's Obligation? 2. Who Is Required To Meet the Renewable Fuels Obligation? 3. What Exemptions Are Available Under the RFS Program? a. Small Refinery and Small Refiner Exemption b. General Hardship Exemption c. Temporary Hardship Exemption Based on Unforeseen Circumstances 4. What Are the Opt-in and State Waiver Provisions Under the RFS Program? a. Opt-in Provisions for Noncontiguous States and Territories b. State Waiver Provisions D. How Do Obligated Parties Comply With the Standard? 1. Why Use Renewable Identification Numbers? a. RINs Serve the Purpose of a Credit Trading Program b. Alternative Approach To Tracking Batches 2. Generating RINs and Assigning Them to Batches a. Form of Renewable Identification Numbers b. Generating RINs c. Cases in Which RINS Are Not Generated 3. Calculating and Reporting Compliance a. Using RINs To Meet the Standard b. Valid Life of RINs c. Cap on RIN Use To Address Rollover d. Deficit Carryovers 4. Provisions for Exporters of Renewable Fuel 5. How Will the Agency Verify Compliance? E. How Are RINs Distributed and Traded? 1. Distribution of RINs With Volumes of Renewable Fuel a. Responsibilities of Renewable Fuel Producers and Importers b. Responsibilities of Parties That Buy, Sell, or Handle Renewable Fuels c. Batch Splits and Batch Mergers 2. Separation of RINs From Volumes of Renewable Fuel 3. Distribution of Separated RINs 4. Alternative Approaches to RIN Distribution IV. Registration, Recordkeeping, and Reporting Requirements A. Introduction B. Registration 1. Who Must Register Under the RFS Program? 2. How Do I Register? 3. How Do I Know I am Properly Registered With EPA? 4. How are Small Volume Domestic Producers of Renewable Fuels Treated for Registration Purposes? C. Reporting 1. Who Must Report Under the RFS Program? 2. What Reports Are Required Under the RFS Program? 3. What Are the Specific Reporting Items for the Various Types of Parties Required To Report? 4. What are the Reporting Deadlines? 5. How May I Submit Reports to EPA? 6. What Does EPA Do With the Reports it Receives? 7. May I Claim Information in Reports as CBI and How Will EPA Protect it? 8. How are Spilled Volumes With Associated Lost RINs To Be Handled in Reports? D. Recordkeeping 1. What Types of Records Must Be Kept? 2. What Recordkeeping Requirements are Specific to Producers of Cellulosic or Waste-Derived Ethanol? E. Attest Engagements 1. What Are the Attest Engagement Requirements Under the RFS Program? 2. Who Is Subject to the Attest Engagement Requirements for the RFS Program? 3. How Are the Attest Engagement Requirements in this Final Rule Different From Those Proposed? V. What Acts Are Prohibited and Who Is Liable for Violations? VI. Current and Projected Renewable Fuel Production and Use A. Overview of U.S. Ethanol Industry and Future Production/Consumption 1. Current Ethanol Production 2. Expected Growth in Ethanol Production 3. Current Ethanol and MTBE Consumption 4. Expected Growth in Ethanol Consumption B. Overview of Biodiesel Industry and Future Production/Consumption 1. Characterization of U.S. Biodiesel Production/Consumption 2. Expected Growth in U.S. Biodiesel Production/Consumption C. Feasibility of the RFS Program Volume Obligations 1. Production Capacity of Ethanol and Biodiesel 2. Technology Available To Produce Cellulosic Ethanol a. Sugar Platform i. Pretreatment ii. Dilute acid hydrolysis iii. Concentrated acid hydrolysis iv. Enzymatic hydrolysis b. Syngas Platform c. Plasma Technology d. Feedstock Optimization 3. Renewable Fuel Distribution System Capability VII. Impacts on Cost of Renewable Fuels and Gasoline A. Renewable Fuel Production and Blending Costs 1. Ethanol Production Costs a. Corn Ethanol b. Cellulosic Ethanol 2. Biodiesel Production Costs 3. Diesel Fuel Costs B. Distribution Costs 1. Ethanol Distribution Costs a. Capital Costs To Upgrade Distribution System for Increased Ethanol Volume b. Ethanol Freight Costs 2. Biodiesel Distribution Costs C. Estimated Costs to Gasoline 1. Description of Cases Modeled a. Base Case
(2004)b. Reference Case
(2012)c. Control Cases
(2012)2. Overview of Cost Analysis Provided by the Contractor Refinery Model 3. Overall Impact on Fuel Cost a. Cost Without Ethanol Subsidies b. Gasoline Costs Including Ethanol Consumption Tax Subsidies VIII. What Are the Impacts of Increased Ethanol Use on Emissions and Air Quality? A. Effect of Renewable Fuel Use on Emissions 1. Emissions From Gasoline Fueled Motor Vehicles and Equipment a. Gasoline Fuel Quality b. Emissions From Motor Vehicles c. Nonroad Equipment 2. Diesel Fuel Quality: Biodiesel 3. Renewable Fuel Production and Distribution B. Impact on Emission Inventories 1. Primary Analysis 2. Sensitivity Analysis 3. Local and Regional VOC and NO <sup>X</sup> Emission Impacts in July C. Impact on Air Quality 1. Impact of Increased Ethanol Use on Ozone 2. Particulate Matter IX. Impacts on Fossil Fuel Consumption and Related Implications A. Impacts on Lifecycle GHG Emissions and Fossil Energy Use 1. Time Frame and Volumes Considered 2. GREET Model a. Renewable Fuel Pathways Considered b. Modifications to GREET c. Sensitivity Analysis 3. Displacement Indexes
(DI)4. Impacts of Increased Renewable Fuel Use a. Greenhouse Gases and Carbon Dioxide b. Fossil Fuel and Petroleum B. Implications of Reduced Imports of Petroleum Products C. Energy Security Implications of Increases in Renewable Fuels 1. Effect of Oil Use on Long-Run Oil Price, U.S. Import Costs, and Economic Output 2. Short-Run Disruption Premium From Expected Costs of Sudden Supply Disruptions 3. Costs of Existing U.S. Energy Security Policies X. Agricultural Sector Economic Impacts XI. Public Participation XII. Administrative Requirements A. Executive Order 12866: Regulatory Planning and Review B. Paperwork Reduction Act C. Regulatory Flexibility Act 1. Overview 2. Background 4. Summary of Potentially Affected Small Entities 5. Impact of the Regulations on Small Entities 6. Small Refiner Outreach 7. Reporting, Recordkeeping, and Compliance Requirements 8. Related Federal Rules 9. Conclusions D. Unfunded Mandates Reform Act E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments G. Executive Order 13045: Protection of Children From Environmental Health and Safety Risks H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer Advancement Act J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations. K. Congressional Review Act L. Clean Air Act Section 307(d) XIII. Statutory A I. Introduction Through today's final rule, we are putting in place a compliance and enforcement program that implements the renewable fuel program, also known as the Renewable Fuel Standard
(RFS)program. This program accomplishes the statutory goal of increasing the volume of renewable fuels that are required to be used in vehicles in the U.S. as required in Section 211(o) of the Clean Air Act
(CAA)enacted as part of the Energy Policy Act of 2005 (the Energy Act or the Act). This final rule resulted from a collaborative effort with stakeholders, including refiners, renewable fuel producers, and distributors, who together helped to design a program that is simple, flexible, and enforceable. As a result of the favorable economics of renewable fuels in comparison to conventional gasoline and diesel, renewable fuel volumes are expected to exceed the requirements of the RFS program. We have evaluated the impacts of a range of renewable fuel volumes as high as 10 billion gallons in 2012. This represents a significant increase over the volume of renewable fuel used in 2004 which was approximately 3.5 billion gallons, and this increase is estimated to produce a number of significant effects. For instance, we estimate that the transition to renewable fuels will reduce petroleum consumption by 2.0 to 3.9 billion gallons or approximately 0.8 to 1.6 percent of the petroleum that would otherwise be used by the transportation sector. The increased use of renewable fuels is also expected to produce reductions in some regulated pollutants. Carbon monoxide emissions from gasoline powered vehicles and equipment will be reduced by 0.9 to 2.5 percent and emissions of benzene (a mobile source air toxic) will be reduced by 1.8 to 4.0 percent. 1 At the same time, other emissions may increase. Nationwide, we estimate between a 41,000 and 83,000 ton increase in VOC + NO <sup>X</sup> emissions. However, the effects will vary significantly by region with some major metropolitan areas experiencing small emission benefits, while other areas may see an increase in VOC emissions from 4 to 5 percent and an increase in NO <sup>X</sup> emissions from 6 to 7 percent from gasoline powered vehicles and equipment. 1 These reductions are relative to the Mobile Source Air Toxics
(MSAT)standards in effect. Additional benzene emission reductions will occur as a result of the recently finalized MSAT2 standards (72 FR 8428, February 26, 2007). The use of renewable fuel will likewise reduce greenhouse gas emissions such as carbon dioxide by 8.0 to 13.1 million metric tons, about 0.4 to 0.6 percent of the anticipated greenhouse gas emissions from the transportation sector in the United States in 2012. Greenhouse gas emissions contribute to climate change, and thus, increased renewable use is an important step in addressing this issue. Finally, we estimate that increases in the use of renewable fuels will increase net farm income and the nation's energy security. Net U.S. farm income is estimated to increase by between $2.6 and $5.4 billion through transfers from users of gasoline and consumers of agricultural products used to produce ethanol. However, as feedstocks used in the production of renewable fuels expand beyond the corn and soybeans that are most common today, the renewable fuels industry is expected to continue to diversify and grow in its ability to benefit the nation's environment and economy. A. The Role of Renewable Fuels in the Transportation Sector Renewable fuels have been an important part of our nation's transportation fuel supply for many years. Following the CAA amendments of 1990, the use of renewable fuels, particularly ethanol, increased dramatically. Several key clean fuel programs required by the CAA established new market opportunities for ethanol. A very successful mobile source control strategy, the reformulated gasoline
(RFG)program, was implemented in 1995. This program set stringent new controls on the emissions performance of gasoline, which were designed to significantly reduce summertime ozone precursors and year round air toxics emissions. The RFG program also required that RFG meet an oxygen content standard. Several areas of the country began blending ethanol into gasoline to help meet this new standard, such as Chicago and St. Louis. Another successful clean fuel strategy required certain areas exceeding the national ambient air quality standard for carbon monoxide to also meet an oxygen content standard during the winter time to reduce harmful carbon monoxide emissions. Many of these areas, such as Denver and Phoenix, also blended ethanol during the winter months to help meet this new standard. Today, the role and importance of renewable fuels in the transportation sector continue to expand. In the past several years as crude oil prices have soared above the lower levels of the 1990's, the relative economics of renewable fuel use have improved dramatically. In addition, since the vast majority of crude oil produced in or imported into the U.S. is consumed as gasoline or diesel fuel in the U.S., concerns about our dependence on foreign sources of crude oil have renewed interest in renewable transportation fuels. The emergence of more in-depth understanding of the impacts of human activities on climate change has also focused attention on the various ways that renewable fuels can reduce the consumption of fossil fuels. The passage of the Energy Policy Act of 2005 demonstrated a strong commitment on the part of U.S. policymakers to consider additional means of supporting renewable fuels as a supplement to petroleum-based fuels in the transportation sector. The RFS program is one such means. The RFS program was debated by the U.S. Congress over several years before finally being enacted through passage of the Energy Policy Act of 2005. The RFS program is first and foremost designed to increase the use of renewable fuels in motor vehicle fuel consumed in the U.S. In this context, it is expected to simultaneously reduce dependence on foreign sources of petroleum, increase domestic sources of energy, and diversify our energy portfolio to help transition to alternatives to petroleum in the transportation sector. Based on our analysis, we also believe that the expanded use of renewable fuels will provide reductions in carbon dioxide emissions that contribute to climate change and in air toxics emissions such as benzene from the transportation sector, while other emissions such as hydrocarbons and oxides of nitrogen are projected to increase. The increased use of renewable fuels such as ethanol and biodiesel is also expected to have the added effect of providing an expanded market for agricultural products such as corn and soybeans. The expected increase in cellulosic ethanol production will also expand the market opportunities to a wider array of feedstocks. The requirement for use of a specified volume of renewable fuels complements other provisions of the Energy Act. In particular, the required volume of renewable fuel use will offset any possible loss in demand for renewable fuels occasioned by the Act's repeal of the oxygen content mandate in the RFG program while allowing greater flexibility in how renewable fuels are blended into the nation's fuel supply. The RFS program also creates a specific annual level for minimum renewable fuel use which increases over time, ensuring overall growth in the demand and opportunity for renewable fuels. Because renewable fuels such as ethanol and biodiesel are not new to the U.S. transportation sector, the expansion of their use is expected to follow distribution and blending practices already in place. For instance, the market already has the necessary production and distribution mechanisms in place in many areas and the ability to expand these mechanisms into new markets. Recent spikes in ethanol use resulting first from the state MTBE bans, and now the virtual elimination of MTBE from the marketplace, have tested the limits of the ethanol distribution system. However, future growth is expected to move in a more orderly fashion since the use of renewable fuels will not be geographically constrained and, given EIA volume projections, investment decisions can follow market forces rather than regulatory mandates. In addition, the increased production volumes of ethanol and the expanded penetration of ethanol in new markets may create new opportunities for blending of E85, a blend of 85 percent ethanol and 15 percent gasoline, in the long run. The increased availability of E85 will mean that more flexible fueled vehicles
(FFV)can use this fuel. Of the approximately 5 million FFVs currently in use in the U.S, most are currently fueled with conventional gasoline rather than E85, in part due to the limited availability of E85. Given the ever-increasing demand for petroleum-based products in the transportation sector, the RFS program also moves the nation in the direction of replacing part of this demand with renewable energy. The RFS program provides the certainty that at least a minimum amount of renewable fuel will be used in the U.S., which in turn provides some certainty for investment in production capacity of renewable fuels. However, it should be understood that the RFS program is not the only factor currently impacting demand for ethanol and other renewable fuels. As Congress was developing the RFS program in the Energy Act, several large states were adopting and implementing bans on the use of MTBE in gasoline. As a result, refiners supplying reformulated gasoline
(RFG)in those states switched to ethanol to satisfy the oxygen content mandate for their RFG, causing a large, sudden increase in demand for ethanol. Even more importantly, with the removal of the oxygen content mandate for RFG, refiners elected to remove essentially all MTBE from the gasoline supply in the U.S. during the spring of 2006. In order to accomplish this transition quickly, while still maintaining gasoline volume, octane, and gasoline air toxics performance standards, refiners elected to blend ethanol into virtually all reformulated gasoline nationwide. This caused a second dramatic increase in demand for ethanol, which in the near term was met by temporarily shifting large volumes of ethanol out of conventional gasoline and into the RFG areas. Perhaps the largest impact on renewable fuel demand, however, has been the increase in the cost of crude oil. In the last few years, both crude oil prices and crude oil price forecasts have increased dramatically. This has resulted in a large economic incentive for the use of ethanol and biodiesel. The Energy Information Administration
(EIA)and others are currently projecting renewable fuel demand to exceed the minimum volumes required under the RFS program by a substantial margin. In this context, the effect of the RFS program is to provide a minimum level of demand to support ongoing investment in renewable fuel production. However, market demand for renewable fuels is expected to exceed the statutory minimums. We believe that the program we are finalizing today will operate effectively regardless of the level of renewable fuel use or market conditions in the energy sector. B. Requirements in the Energy Policy Act Section 1501 of the Energy Policy Act amended the Clean Air Act and provides the statutory basis for the RFS program in Section 211(o). It requires EPA to establish a program to ensure that the pool of gasoline sold in the contiguous 48 states contains specific volumes of renewable fuel for each calendar year starting with 2006. The required overall volumes for 2006 through 2012 are shown in Table I.B-1 below. Table I.B-1.— Applicable Volumes of Renewable Fuel Under the RFS Program Calendar year Billion gallons 2006 2006 4.0 2007 4.7 2008 5.4 2009 6.1 2010 6.8 2011 7.4 2012 7.5 In order to ensure the use of the total renewable fuel volume specified for each year, the Agency must set a standard for each year representing the amount of renewable fuel that each refiner, blender, or importer must use, expressed as a percentage of gasoline sold or introduced into commerce. This yearly percentage standard is to be set at a level that will ensure that the total renewable fuel volumes shown in Table I.B-1 will be used based on gasoline volume projections provided by the Energy Information Administration (EIA). The standard for each year must be published in the **Federal Register** by November 30 of the previous year. Starting with 2013, EPA is required to establish the applicable national volume, based on the criteria contained in the statute, which must require at least the same overall percentage of renewable fuel use as was required in 2012. The Act defines renewable fuels primarily on the basis of the feedstock. In general, renewable fuel must be a motor vehicle fuel that is produced from plant or animal products or wastes, as opposed to fossil fuel sources. The Act specifically identifies several types of motor vehicle fuels as renewable fuels, including cellulosic biomass ethanol, waste-derived ethanol, biogas, biodiesel, and blending components derived from renewable fuel. The standard set annually by EPA is to be a single percentage applicable to refiners, blenders, and importers, as appropriate. The percentage standard is used by obligated parties to determine a volume of renewable fuel that they are responsible for introducing into the domestic gasoline pool for the given year. The percentage standard must be adjusted such that it does not apply to multiple parties for the same volume of gasoline. The standard must also take into account the use of renewable fuel by small refineries that are exempt from the program until 2011. Under the Act, the required volumes in Table I.B-1 apply to the contiguous 48 states. However, Alaska and Hawaii can opt into the program, in which case the pool of gasoline used to calculate the standard, and the number of regulated parties, would change. In addition, other states can request a waiver of the RFS program under certain conditions, which would affect the national quantity of renewable fuel required under the program. The Act requires the Agency to promulgate a credit trading program for the RFS program whereby an obligated party may generate credits for over-complying with their annual obligation. The obligated party can then use these credits to meet their requirements in the following year or trade them for use by another obligated party. Thus the credit trading program allows obligated parties to comply in the most cost-effective manner by permitting them to generate, transfer, and use credits. The trading program also permits renewable fuels that are not blended into gasoline, such as biodiesel, to participate in the RFS program. The Agency must determine who can generate credits, under what conditions credits may be traded, how credits may be transferred from one party to another, and the appropriate value of credits for different types of renewable fuel. If a party is not able to generate or purchase sufficient credits to meet their annual obligation, they are allowed to carry over the deficit to the next annual compliance period, but must achieve full compliance in that following year. C. Development of the RFS Program Section 1501 of the Energy Act prescribed the RFS program, including the required total volumes, the timing of the obligation, the parties who are obligated to comply, the definition of renewable fuel, and the general framework for a credit trading program. Various aspects of the program require additional development by the Agency beyond the specifications in the Act. The Agency must develop regulations to ensure the successful implementation of the RFS program, based on the framework spelled out in the statute. Under the RFS program the trading provisions comprise an integral element of compliance. Many obligated parties do not have access to renewable fuels or the ability to blend them, and so must use credits to comply. The RFS trading program is also unique in that the parties liable for meeting the standard (refiners, importers, and blenders of gasoline) are not generally the parties who make the renewable fuels or blend them into gasoline. This creates the need for trading mechanisms that ensure that the means to demonstrate compliance will be readily available for use by obligated parties. The first step we took in developing the proposed program was to seek input and recommendations from the affected stakeholders. There were initially a wide range of thoughts and views on how to design the program. However, there was broad consensus that the program should satisfy a number of guiding principles, including, for example, that the compliance and trading program should provide certainty to the marketplace and minimize cost to the consumers; that the program should preserve existing business practices for the production, distribution, and use of both conventional and renewable fuels; that the program should be designed to accommodate all qualifying renewable fuels; that all renewable volumes produced are made available to obligated parties for compliance; and that the Agency should have the ability to easily verify compliance to ensure that the volume obligations are in fact met. These guiding principles and the comments we received on our Notice of Proposed Rulemaking
(NPRM)helped to move us toward the program in today's final rule. We published a Notice of Proposed Rulemaking on September 22, 2006 (71 FR 55552) which described our proposed approach to compliance and the trading program, as well as preliminary analyses of the environmental and economic impacts of increased use of renewable fuels. The program finalized today largely mirrors the proposed program, with some revisions reflecting continued input from stakeholders during the formal comment period. II. Overview of the Program Today's action establishes the final requirements for the RFS program, as well as our assessment of the environmental and economic impacts of the nation's transition to greater use of renewable fuels. This section provides an overview of our program and renewable fuel impacts assessment. Sections III through V provide the details of the structure of the program, while Sections VI through X describe our assessment of the impacts on emissions of regulated pollutants and greenhouse gases, air quality, fossil fuel use, energy security, economic impacts in the agricultural sector, and cost from the expanded use of renewable fuels. A. Impacts of Increased Reliance on Renewable Fuels In a typical major rulemaking, EPA would conduct a full assessment of the economic and environmental impacts of the specific rule that it is promulgating. However, as discussed in Section I.A., the replacement of MTBE with ethanol and the extremely favorable economics for renewable fuels brought on by the rise in crude oil prices are causing renewable fuel use to far exceed the RFS requirements. Given these circumstances, it is important to assess the impacts of this larger increase in renewable use and the related changes occurring to gasoline. For this reason we have carried out an assessment of the economic and environmental impacts of the broader changes in fuel quality resulting from our nation's transition to greater utilization of renewable fuels, as opposed to an assessment that is limited to the RFS program itself. To carry out our analyses, we elected to use 2004 as the baseline from which to compare the impacts of expanded renewable use. We chose 2004 as a baseline primarily due to the fact that all the necessary refinery production data, renewable fuel production data, and fuel quality data were already in hand at the time we needed to begin the analysis. We did not use 2005 as a baseline year because 2005 may not be an appropriate year for comparison due to the extraordinary impacts of hurricanes Katrina and Rita on gasoline production and use. To assess the impacts of anticipated increases in renewable fuels, we elected to look at what they would be in 2012, the year the statutorily-mandated renewable fuel volumes will be fully phased in. By conducting the analysis in this manner, the impacts include not just the impact of expanded renewable fuel use by itself, but also the corresponding decrease in the use of MTBE, and the potential for oxygenates to be removed from RFG due to the absence of the RFG oxygenate mandate. Since these three changes are all inextricably linked and are occurring simultaneously in the marketplace, evaluating the impacts in this manner is both necessary and appropriate. We evaluated the impacts of expanded renewable fuel use and the corresponding changes to the fuel supply on fuel costs, consumption of fossil fuels, and some of the economic impacts on the agricultural sector and energy security. We also evaluated the impacts on emissions, including greenhouse gas emissions that contribute to climate change, and the corresponding impacts on nationwide and regional air quality. Our analyses are summarized in this section. 1. Renewable Fuel Volume Scenarios Analyzed As shown in Table I.B-1, the Act stipulates that the nationwide volumes of renewable fuel required under the RFS program must be at least 4.0 billion gallons in 2006 and increase to 7.5 billion gallons in 2012. However, we expect that the volume of renewable fuel will actually exceed the required volumes by a significant margin. Based on economic modeling in 2006, EIA projected renewable fuel demand in 2012 of 9.6 billion gallons for ethanol, and approximately 300 million gallons for biodiesel using crude oil prices forecast at $48 per barrel. 2 Therefore, in assessing the impacts of expanded use of renewable fuels, we evaluated two comparative scenarios, one representing the statutorily required minimum, and another reflecting the higher levels projected by EIA. Although the actual renewable fuel volumes produced in 2012 may differ from both the required and projected volumes, we believe that these two volume scenarios together represent a reasonable range for analysis purposes. 3 2 $48/barrel from Annual Energy Outlook 2006, Energy Information Administration, Department of Energy. 3 Subsequent to the analysis for this final rule, EIA has released its 2007 AEO forecasts for ethanol use, which increase the projection to 11.2 billion gallons by 2012. The Act also stipulates that at least 250 million gallons out of the total volume required in 2013 and beyond must meet the definition specified for cellulosic biomass ethanol. As described in Section VI, there are a number of companies already making plans to produce ethanol from cellulosic feedstocks and/or waste-derived energy sources that could potentially meet the definition of cellulosic biomass ethanol. Accordingly, we anticipate a ramp-up in production of cellulosic biomass ethanol production in the coming years, and for analysis purposes we have assumed that 250 million gallons of cellulosic biomass ethanol will be used in 2012. As discussed in Section VI, we chose 2004 to represent current baseline conditions. However, a direct comparison of the fuel quality impacts on emissions and air quality that are expected to occur once the RFS program is fully phased in required that changes in overall fuel volume, fleet characterization, and other factors be constant. Therefore, we created a 2012 reference case from the 2004 base case for use in the emissions and air quality analysis that maintained current fuel quality parameters while incorporating forecasted increases in vehicle miles traveled and changes in fleet demographics. The 2012 fuel reference case was developed by growing out the 2004 renewable fuel baseline according to EIA's forecasted energy growth rates between 2004 and 2012. For the analyses, we created two 2012 scenarios representing expanded renewable fuel production. The “RFS Case” represents volume levels designed to exactly meet the requirements of the RFS program, and includes the effects of higher credit values for cellulosic ethanol and biodiesel. Since higher credit values mean that one gallon of renewable fuel counts as more than one gallon for compliance purposes, less than 7.5 billion gallons of renewable fuel is needed to meet the 7.5 billion gallon statutory requirement, but credits equivalent to 7.5 billion gallons of renewable fuel would still be available for compliance purposes. The “EIA Case” represents volume levels based on EIA projections. A summary of the assumed renewable fuel volumes for the scenarios we evaluated is shown in Table II.A.1-1. Details of the calculations used to determine these volumes are given in Chapter 2 of the Regulatory Impact Analysis
(RIA)in the docket for this rulemaking. Table II.A.1-1.—Renewable Fuel Volume Scenarios (Billion Gallons) 2004 base case 2012 Reference case RFS case EIA case Corn-ethanol 3.548 3.947 6.421 9.388 Cellulosic ethanol 0 0 0.25 0.25 Biodiesel 0.025 0.030 0.303 0.303 Total volume 3.573 3.977 6.974 9.941 2. Emissions We evaluated the impacts of increased use of ethanol and biodiesel on emissions and air quality in the U.S. relative to the reference case. We estimated that nationwide VOC emissions in 2012 from gasoline vehicles and equipment will increase by about 0.3% in the RFS Case and about 0.7% in the EIA Case. For NO <sup>X</sup> , we estimated that nationwide annual emissions in 2012 will increase about 0.9% for the RFS Case and 1.6% for the EIA Case. These increases are equivalent to an additional 18,000 to 43,000 tons of VOC per year, and an additional 23,000 to 40,000 tons of NO <sup>X</sup> per year. We also estimated the change in emissions in those areas which are projected to experience a significant change in ethanol use; i.e., where the market share of ethanol blends was projected to change by 50 percent or more. We focused on July emissions since these are most relevant to ozone formation and modeled 2015 because our ozone model is based upon a 2015 emissions inventory (though we would expect similar results in 2012). Finally, we developed separate estimates for RFG areas, low RVP areas (i.e., RVP standards less than 9.0 RVP), and conventional gasoline areas with a summer 9.0 RVP standard. For areas with a significant change in ethanol use, compared to the reference case, VOC emissions in RFG areas increased by up to 2.3%, while NO <sup>X</sup> emissions increased by up to 1.6%. In low RVP areas, VOC emissions increased by up to 4.6%, while NO <sup>X</sup> emissions increased by up to 6.2%. In 9.0 RVP areas, VOC emissions increased by up to 4.6%, while NO <sup>X</sup> emissions increased by up to 7.3%. Unlike VOC and NO <sup>X</sup> , emissions of CO and benzene from gasoline vehicles and equipment were estimated to decrease in 2012 when the use of renewable fuels increased. Reductions in emissions of CO varied from 0.9% percent to as high as 2.5% percent for the nation as a whole, depending on the renewable fuel volume scenario. Similarly, benzene emissions from gasoline vehicles and equipment were estimated to be reduced from 1.8% to 4.0% percent. We do not have sufficient data to predict the effect of ethanol use on levels of either directly emitted particulate matter
(PM)or secondarily formed PM. The increased NO <sup>X</sup> emissions are expected to lead to increases in secondary nitrate PM, but at the same time reduced aromatics resulting from ethanol blending are likely to lead to a decrease in secondary organic PM, as discussed in Section VIII.C. In addition, biodiesel use is expected to result in some reduction in direct PM emissions, though small in magnitude due to the relatively small volumes. The emission impact estimates described above are based on the best available data and models. However, it must be highlighted that most of the fuel effect estimates are based on very limited or old data which may no longer be reliable in estimating the emission impacts on vehicles in the 2012 fleet with advanced emission controls. 4 As such, these emission estimates should be viewed as preliminary. EPA hopes to conduct significant new testing in order to better estimate the impact of fuel changes on emissions from both highway vehicles and nonroad equipment, including those fuel changes brought about by the use of renewable fuels. We hope to be able to incorporate the data from such additional testing into the analyses for other studies required by the Energy Act, and into a subsequent rule to set the RFS program standard for 2013 and later. 4 Advanced emission controls include close-coupled, high-density catalysts and their associated electronic control systems for light-duty vehicles, and NO <sup>X</sup> adsorbers and PM traps for heavy-duty engines. We used the Ozone Response Surface Model
(RSM)to estimate the impacts of the increased use of ethanol on ozone levels for both the RFS Case and the EIA Case. The ozone RSM approximates the effect of VOC and NO <sup>X</sup> emissions in a 37-state eastern area of the U.S. Using this model, we projected that the changes in VOC and NO <sup>X</sup> emissions could produce a very small increase in ambient ozone levels. On average, population-weighted ozone design value concentrations increased by about 0.05 ppb, which represents 0.06 percent of the standard. Even for areas expected to experience a significant increase in ethanol use, population-weighted ozone design value concentrations increased by only 0.15 to 0.18 ppb, about 0.2 percent of the standard. These ozone impacts do not consider the reductions in CO emissions mentioned above, or the change in the types of compounds comprising VOC emissions. Directionally, both of these factors may mitigate these ozone increases. We investigated several other issues related to emissions and air quality that could affect our estimates of the impacts of increased use of renewable fuels. These are discussed in Section VIII and in greater detail in the RIA. For instance, our current models assume that recent model year vehicles are insensitive to many fuel changes. However, a limited amount of new test data suggest that newer vehicles may be just as sensitive as older model year vehicles. Our sensitivity analysis suggests that if this is the case, VOC emissions could decrease by as much as 0.3%, instead of increasing by up to 0.7%. NO <sup>X</sup> emissions could increase by up to 4.2%, up from a 1.6% increase. We also evaluated the emissions from the production of both ethanol and biodiesel fuel and determined that they will also increase with increased use of these fuels. Nationwide, emissions related to the production and distribution of ethanol and biodiesel fuel are projected to be of the same order of magnitude as the emission impacts related to the use of these fuels in vehicles. Finally, a lack of emission data and atmospheric modeling tools prevented us from making specific projections of the impact of renewable fuels on ambient PM levels. As mentioned, however, ethanol use may affect ambient PM levels due to the increase in NO <sup>X</sup> emissions and the reduction in the aromatic content of gasoline, which should reduce aromatic VOC emissions. All of these issues will be the subject of further study and analysis in the future. 3. Economic Impacts In Section VII of this preamble, we estimate the cost of producing the extra volumes of renewable fuel anticipated through 2012. For corn ethanol, we estimate the per gallon cost of ethanol to range from $1.26 per gallon in 2012 (2004 dollars) in the RFS Case to $1.32 per gallon in the EIA Case. These costs take into account the cost of the feedstock (corn), plant equipment and operation and the value of any co-products (distiller's dried grain and solubles, for example). For biodiesel, we estimate the per gallon cost to be between $1.89 and $2.06 per gallon if produced using soy bean oil, and less if using yellow grease ($1.11 to $1.56 per gallon) or other relatively low cost or no-cost feedstocks. The price paid for ethanol, however, is reduced by the $0.51 per gallon federal tax subsidy as well as any state subsidies that might apply. Similarly the price paid for biodiesel is reduced due to the $1.00 per gallon federal tax subsidy biodiesel produced from soy bean oil and $0.50 per gallon tax subsidy for biodiesel produced from yellow grease. We also note that these costs represent the production cost of the fuel and not the market price. In recent years, the prices of ethanol and biodiesel have tended to track the prices of gasoline and diesel fuel, in some cases even exceeding those prices. These renewable fuels are then blended in gasoline and diesel fuel. While biodiesel is typically just blended with typical petroleum diesel, additional efforts are sometimes necessary and/or economically advantageous at the refiner level when adding ethanol to gasoline. For example, ethanol's high octane reduces the need for other octane enhancements by the refiner, whereas offsetting the volatility increase caused by ethanol may require removal of other highly volatile components. Section VII examines these fuel cost impacts and concludes that the net cost to society in 2012 in comparison to the reference case will range from an estimate of 0.5 cent to 1.0 cent per gallon of gasoline due to the increased use of renewable fuels and their displacement of MTBE. The resulting total nationwide costs in 2012 are $823 million per year for the RFS case and $1,739 million per year for the EIA case. This total excludes the effects of the 51 cent/gal federal excise tax credit as well as state tax subsidies. Our estimates of fuel impacts do not consider other societal benefits. For example, the displacement of petroleum-based fuel (largely imported) by renewable fuel (largely produced in the United States), should reduce our use of imported oil and fuel. We estimate that 95 percent of the lifecycle petroleum reductions resulting from the use of renewable fuel will be met through reductions in net petroleum imports. In Section IX of this preamble we estimate the value of the decrease in imported petroleum at about $2.6 billion in 2012 for the RFS Case and $5.1 billion for the EIA Case, in comparison to our 2012 reference case. Total petroleum import expenditures in 2012 are projected to be about $698 billion. Furthermore, the above estimate on reduced petroleum import expenditures only partly assess the economic impacts. One of the effects of increased use of renewable fuel is that it diversifies the energy sources used in making transportation fuel. To the extent that diverse sources of fuel energy reduce the dependence on any one source, the risks, both financial as well as strategic, of a potential disruption in supply reflected in the price volatility of a particular energy source are reduced. As indicated in the proposal, EPA has worked with researchers at Oakridge National Laboratory to update a study they previously published and which has been used or cited in several government actions impacting oil consumption. A draft report is being made available in the docket at this time for further consideration. This analysis only looks at the impact of reduced petroleum imports on energy security. Other energy security issues could arise with the wider use of biofuels. For example, ethanol's production and costs are determined by the availability of corn as a feedstock. Corn production, in turn, is weather-dependent. Also, the use of biofuels may increase the use of natural gas. A full integrated analysis of the energy security implications of the wider use of biofuels has yet to be undertaken. While increased use of renewable fuel will reduce expenditures on imported oil, it will also increase expenditures on renewable fuels and in-turn, on the sources of those renewable fuels. The RFS program attempts to spur the increased use of renewable transportation fuels made principally from agricultural crops produced in the U.S. As a result, it is important to analyze the consequences of the transition to greater renewable fuel use in the U.S. agricultural sector. To perform this analysis, EPA selected the Forest and Agricultural Sector Optimization Model (FASOM) developed by Professor Bruce McCarl of Texas A&M University and others over the past thirty years. FASOM is a dynamic, nonlinear programming model of the agriculture and forestry sectors of the U.S. (For this analysis, we focused on the agriculture portion of the model.) Due to the greater demand for corn as a feedstock for ethanol production, corn prices are estimated to increase in 2012 by 18 cents per bushel for the RFS Case and 39 cents per bushel of corn for the EIA Case from $2.32 (in 2004 dollars) in the Reference Case. Although soybean prices are expected to rise slightly, the increased cost is likely due to higher input costs, such as land prices. We estimate a price increase of 18 cents (RFS Case) to 21 cents (EIA Case) per bushel of soybeans from a Reference Case price of $5.26 per bushel. These higher commodity prices are predicted to also result in higher U.S. farm income. Our analysis predicts that farm income will increase by $2.6 billion annually by 2012 for the RFS Case and $5.4 billion for the EIA Case, roughly a 5 to 10 percent increase. Due to higher corn prices, U.S. exports of corn are estimated to decrease by $573 million in the RFS Case and by $1.29 billion in the EIA Case in 2012. With higher commodity prices, we would expect some upward pressure on food costs as the higher cost of corn and soybeans is passed along to consumers. We estimate a relatively modest increase in annual household food costs associated with the higher price commanded by corn and soybeans. For the RFS Case, annual per capita wholesale food cost are estimated to increase by approximately $7, while the higher renewable fuel volumes anticipated by the EIA Case will result in a $12 annual increase in the per capita wholesale food cost. This equates to roughly a $2.1 to $3.6 billion increase in nationwide food costs in 2012. 4. Greenhouse Gases and Fossil Fuel Consumption There has been considerable interest in the impacts of fuel programs on greenhouse gases implicated in climate change and on fossil fuel consumption due largely to concerns about dependence on foreign sources of petroleum. Therefore, in this rulemaking we have undertaken an analysis of the greenhouse gas and fossil fuel consumption impacts of a transition to greater renewable fuel use. This is the first analysis of its kind in a high profile rule, and as such it may guide future work in this area. As a result of the transition to greater renewable fuel use, some petroleum-based gasoline and diesel will be directly replaced by renewable fuels. Therefore, consumption of petroleum-based fuels will be lower than it would be if no renewable fuels were used in transportation vehicles. However, a true measure of the impact of greater use of renewable fuels on petroleum use, and indeed on the use of all fossil fuels, accounts not only for the direct use and combustion of the finished fuel in a vehicle or engine, but also includes the petroleum use associated with production and transportation of that fuel. For instance, fossil fuels are used in producing and transporting renewable feedstocks such as plants or animal byproducts, in converting the renewable feedstocks into renewable fuel, and in transporting and blending the renewable fuels for consumption as motor vehicle fuel. Likewise, fossil fuels are used in the production and transportation of petroleum and its finished products. In order to estimate the true impacts of increases in renewable fuel use on fossil fuel use, we must take these steps into account. Such analyses are termed lifecycle analyses. There is also no consensus on the most appropriate approach for conducting such lifecycle analyses. We have chosen to base our lifecycle analysis on Argonne National Laboratory's GREET model for the reasons described in Section IX. However, there are other lifecycle models in use. The choice of model inputs and assumptions all have a bearing on the results of lifecycle analyses, and many of these assumptions remain the subject of debate among researchers. With these caveats, we compared the lifecycle impacts of renewable fuels to the petroleum-based gasoline and diesel fuels that they replace. This analysis allowed us to estimate not only the overall impacts of renewable fuel use on petroleum use, but also on emissions of greenhouse gases such as carbon dioxide from all fossil fuels. In comparison to the reference case, we estimate that the increased use of renewable fuels in the RFS and EIA cases will reduce transportation sector petroleum consumption by about 0.8 and 1.6 percent, respectively, in the transportation sector in 2012. This is equivalent to 2.0-3.9 billion gallons of petroleum in 2012. We also estimated that greenhouse gases from the transportation sector will be reduced by about 0.4 and 0.6 percent for the RFS and EIA cases, respectively, equivalent to about 8-13 million metric tons. These reductions are projected to continue to increase beyond 2012 since crude oil prices have been projected by EIA to continue to be high relative to the prices of the 1990's, and as a result there is expected to be an economic advantage to using renewable fuels beyond 2012. These greenhouse gas emission reductions are also highly dependent on the expectation that the majority of the future ethanol use will be produced from corn. If advances in the technology for converting cellulosic feedstocks into ethanol allow cellulosic ethanol use to exceed the levels assumed in our analysis, then even greater greenhouse gas reductions may result. 5 5 Cellulosic ethanol is estimated to provide a comparable petroleum displacement as corn derived ethanol on a per gallon basis, though the impacts on total energy and greenhouse gas emissions differ. 5. Post 2012 RFS Standards The Energy Policy Act of 2005, in addition to setting the standards to be adopted through 2012, requires EPA, in coordination with the Departments of Agriculture and Energy, to determine the applicable volume for the renewable fuel standard for the year 2013 and subsequent calendar years. This determination is to be based on a review of the program's implementation in 2006 through 2012 as well as review of the impact of renewable fuels on the environment, air quality, energy security, job creation, rural economic development and the expected annual rate of renewable fuel production, including production of cellulosic ethanol. In today's final rulemaking, we do not suggest any specific renewable fuel volumes for 2013 and beyond that may be appropriate under the statutory criteria. However, we would note that the President, in his State of the Union address this January, set specific goals reducing the amount of gasoline usage in the United States by 20 percent in the next 10 years. This would be accomplished by reforming and modernizing fuel economy standards for cars and setting mandatory fuels standard equivalent to requiring use of 35 billion gallons of renewable and alternative 6 fuels in 2017. Therefore, given the necessity to address the post-2013 period under the Energy Act and the prospect of continued attention by the Administration and Congress to this issue, EPA will continue to devote attention to the issue of renewable and alternative fuel volumes in the post-2013 period. 6 While the RFS program is specific to renewable fuels, the president's goal of 35 billion gallons by 2017 would include not only renewable fuels, but also other types of alternatives fuels. From a program structure perspective, we believe that what we are putting in place today will remain useful as part of a 2013 and later program. For example, EPA considers that the identification of renewable fuel via a Renewable Identification Number (RIN), the determination of liable parties, the averaging, banking and trading system and the recordkeeping and reporting system would all be elements of a post-2013 program. Depending on the structure of any final legislation approved by Congress and signed into law, such elements could also be incorporated into an expanded renewable and alternative fuels program. B. Program Structure The RFS program being finalized today requires refiners, importers, and blenders (other than oxygenate blenders) to show that a required volume of renewable fuel is used in gasoline. The required volume is determined by multiplying their annual gasoline production by a percentage standard specified by EPA. Compliance is demonstrated through the acquisition of unique Renewable Identification Numbers
(RINs)assigned by the producer or importer to every batch of renewable fuel produced or imported. The RIN shows that a certain volume of renewable fuel was produced or imported. Each year, the refiners, blenders and importers obligated to meet the renewable volume requirement (referred to as “obligated parties”) must acquire sufficient RINs to demonstrate compliance with their volume obligation. RINs can be traded, thereby functioning as the credits envisioned in the Act. A system of recordkeeping and electronic reporting for all parties that have RINs ensures the integrity of the RIN pool. This RIN-based system will both meet the requirements of the Act and provide several other important advantages: • Renewable fuel production volumes can be easily verified. • RIN trading can occur in real time as soon as the renewable fuel is produced rather than waiting to the end of the year when an obligated party would determine if it had exceeded the standard. • Renewable fuel can continue to be produced, distributed, and blended in those markets where it is most economical to do so. • Instances of double-counting of renewable fuel claimed for compliance purposes can be identified based on electronically reported data. Our RIN-based trading program is an essential component of the RFS program, ensuring that every obligated party can comply with the standard while providing the flexibility for each obligated party to use renewable fuel in the most economical ways possible. 1. What Is the RFS Program Standard? EPA is required to convert the aggregate national volumes of renewable fuel specified in the Act into corresponding renewable fuel standards expressed as a percent of gasoline production or importation. The renewable volume obligation that will apply to an individual obligated party will then be determined based on this percentage and the total gasoline production or import volume in a calendar year, January 1 through December 31. EPA will publish the percentage standard in the **Federal Register** each November for the following year based on the most recent EIA gasoline demand projections. However, for compliance in 2007 we are publishing the percentage standard in today's action. The standard for 2007 is 4.02 percent. Section III.A describes the calculation of the standard. 2. Who Must Meet the Standard? Under our program, any party that produces or imports gasoline for consumption in the U.S., including refiners, importers, and blenders (other than oxygenate blenders), will be subject to a renewable volume obligation that is based on the renewable fuel standard. These obligated parties will determine the level of their obligation by multiplying the percentage standard by their annual volume of gasoline production or importation. The result will be the renewable fuel volume which each party must ensure is blended into gasoline consumed in the U.S., with credit for certain other renewable fuels that are not blended into gasoline. For 2007, we are requiring that the renewable fuel volume obligation be determined by multiplying the percentage standard by the volume of gasoline produced or imported prospectively from September 1, 2007 until December 31, 2007. While the standard will not apply to all of 2007 gasoline production, we are nevertheless confident that the total volume of renewable fuel used in all of 2007 will still exceed the volume specified in the Act due to expectations that the demand for renewable fuel will exceed the RFS requirements. In determining their annual gasoline production volume, obligated parties must include all of the finished gasoline which they produced or imported for use in the contiguous 48 states, and must also include reformulated blendstock for oxygenate blending (RBOB), and conventional blendstock for oxygenate blending (CBOB). For refiners and importers this includes unfinished gasoline produced or imported that will become gasoline upon addition of an oxygenate downstream of the refiner. Other producers of gasoline, such as blenders, will count as their gasoline production only the volumes of blendstocks which become gasoline upon their addition to finished gasoline, unfinished gasoline, or other blendstocks. Renewable fuels blended into gasoline by any party will not be counted as gasoline for the purposes of calculating the annual gasoline production volume. Small refiners and small refineries are exempt from meeting the renewable fuel requirements through 2010. All gasoline producers located in Alaska, Hawaii, and noncontiguous U.S. territories and parties who import gasoline into these areas will be exempt indefinitely. However, if Alaska, Hawaii or a noncontiguous territory opts into the RFS program, all of the refiners (except for exempt small refiners and refineries), importers, and blenders located in the state or territory will be subject to the renewable fuel standard. Section III.A provides more details on the standard that must be met, while Section III.C describes the parties that are obligated to meet the standard. 3. What Qualifies as a Renewable Fuel? We have designed the program to cover the range of renewable fuels produced today as well as any that might be produced in the future, so long as they meet the Act's definition of renewable fuel and have been registered and approved for use in motor vehicles. In this manner, we believe that the program provides the greatest possible encouragement for the development, production, and use of renewable fuels to reduce our dependence on petroleum as well as to reduce the carbon dioxide emissions that contribute to climate change. In general, renewable fuels must be produced from plant or animal products or wastes, as opposed to fossil fuel sources. Valid renewable fuels include ethanol made from starch seeds, sugar, or cellulosic materials, biodiesel (mono-alkyl esters), non-ester renewable diesel, and a variety of other products. Both renewable fuels blended into conventional gasoline or diesel and those used in their neat (unblended) form as motor vehicle fuel will qualify. Section III.B provides more details on the renewable fuels that will be allowed to be used for compliance with the standard under our program. 4. Equivalence Values of Different Renewables Fuels One question that we faced in developing the program was what value to place on different renewable fuels and on what basis should that value be determined. The Act specifies that each gallon of cellulosic biomass ethanol and waste-derived ethanol be treated as if it were 2.5 gallons of renewable fuel for compliance purposes, but does not specify the values for other renewable fuels. Although in the NPRM we considered a range of options including straight volume, energy content, and requested comment on the merit and basis for setting “Equivalence Values” on several metrics including lifecycle energy or greenhouse gas emissions, for this final rule we are requiring that the “Equivalence Values” for the different renewable fuels be based on their energy content in comparison to the energy content of ethanol, and adjusted as necessary for their renewable content. The result is an Equivalence Value for corn ethanol of 1.0, for biobutanol of 1.3, for biodiesel (mono alkyl ester) of 1.5, for non-ester renewable diesel of 1.7, and for cellulosic ethanol and waste-derived ethanol of 2.5. The proposed methodology can be used to determine the appropriate Equivalence Value for any other potential renewable fuel as well. Section III.B.4 provides details of the determination of Equivalence Values. 5. How Will Compliance Be Determined? Under our program, every gallon of renewable fuel produced or imported into the U.S. must be assigned a unique RIN. A block of RINs would be assigned to any batch of renewable fuel that is valid for compliance purposes under the RFS program. These RINs must be transferred with renewable fuel as ownership of a volume of renewable fuel is initially transferred through the distribution system. Once the renewable fuel is obtained by an obligated party or actually blended into a motor vehicle fuel, the RIN can be separated from the batch of renewable fuel and then either used for compliance purposes, held, or traded. RINs represent proof of production which is then taken as proof of consumption as well, since all but a trivial quantity of renewable fuel produced or imported will be either consumed as fuel or exported. For instance, ethanol produced for use as motor vehicle fuel is denatured specifically so that it can only be used as fuel. Similarly, biodiesel is produced only for use as fuel and has no other significant uses. An obligated party demonstrates compliance with the renewable fuel standard by accumulating sufficient RINs to cover their individual renewable volume obligation. It will not matter whether the obligated party used the renewable fuel themselves. An obligated party's obligation will be to ensure that a certain amount of renewable fuel was used, either by themselves or by someone else, and the RIN is evidence that this occurred for a certain volume of renewable fuel. Exporters of renewable fuel will also be required to acquire RINs in sufficient quantities to cover the volume of renewable fuel exported. RINs claimed for compliance purposes by obligated parties will thus represent renewable fuel actually consumed as motor vehicle fuel in the U.S. RINs are valid for compliance purposes for the calendar year in which they are generated, or the following calendar year. This approach to RIN life is consistent with the Act's prescription that credits be valid for compliance purposes for 12 months as of the date of generation, where credits are generated at the end of a year when compliance is determined. An obligated party can either use RINs to demonstrate compliance, or can transfer RINs to any other party. If an obligated party is not able to accumulate sufficient RINs for compliance in a given year, it can carry a deficit over to the next year so long as the full deficit and obligation is covered in the next year. In order to ensure that previous year RINs are not used preferentially for compliance purposes in a manner that would effectively circumvent the limitation that RINs be valid for only 12 months after the year generated, we are setting a cap on the use of RINs generated the previous year when demonstrating compliance with the renewable volume obligation for the current year. The cap will mean that no more than 20 percent of a current year obligation can be satisfied using RINs from the previous year. In this manner there is no ability for excess renewable fuel use in successive years to cause an accumulation of RINs to significantly depress renewable fuel demand in any future year. In keeping with the Act, excess RINs not used in the year they are generated or in the subsequent year will expire. Section III.D provides more details on how obligated parties must use RINs for compliance purposes. 6. How Will the Trading Program Work? Renewable fuel producers and importers will be required to generate RINs when they produce or import a batch of renewable fuel (unless, for importers, the RINs have been assigned by a foreign producer registered with EPA). They will then be required to transfer those RINs along with the renewable fuel batches that they represent whenever they transfer ownership of the batch to another party. Likewise any other non-obligated party that takes ownership of a volume of renewable fuel with RINs will be required to transfer those RINs with a volume of renewable fuel. The RIN can be separated from renewable fuel only by obligated parties (at the point when they take ownership of the batch) or a party that converts the renewable fuel into motor vehicle fuel (such as upon blending with gasoline or diesel). Once a RIN is separated from a volume of renewable fuel, it can be used for compliance purposes, banked, or traded to another party. Separated RINs can be transferred to any party any number of times. Recordkeeping and reporting requirements will apply to any party that takes ownership of RINs, whether through the ownership of a batch of renewable fuel or through the transfer of separated RINs. Thus obligated parties can acquire RINs directly through the purchase of renewable fuel with assigned RINs or through the open market for RINs that is allowed under this proposal. Section III.E provides more details on how our RIN trading program will work. 7. How Will the Program Be Enforced? As in all EPA fuel regulations, there is a system of registration, recordkeeping, and reporting requirements for obligated parties, renewable producers and importers (RIN generators), and any parties that procure or trade RINs either as part of their renewable purchases or separately. In most cases, the recordkeeping requirements are not significantly different from what these parties might be doing already as a part of normal business practices. The lynch pin to the compliance program, however, is the unique RIN number itself coupled with an electronic reporting system where RIN generation, RIN use, and RIN transactions will be reported and verified. Thus, EPA, as well as industry can have confidence that invalid RINs are not generated and that there is no double counting. C. Voluntary Green Labeling Program In the proposal EPA asked for comments on the idea of creating a voluntary labeling program to encourage the adoption and use of practices that minimize the environmental concerns associated with renewable fuel production. The proposal suggested adding a “G” (for green) to the end of the RIN of a fuel to indicate that a gallon of renewable fuel was produced with the combination of best farming practices and environmentally friendly production methods and facilities. EPA received a number of comments on this idea. The majority of respondents were very supportive of voluntary labeling and encouraged EPA to establish this program through this final rulemaking. Two commenters opposed the labeling concept, telling EPA that the number and complexity of issues associated with fuel production, and particularly with farming practices, would make such a program impractical and difficult to implement. EPA also was told that it would be hard to audit such a program. Most commenters agreed that using the RIN to host the label makes sense, however the use of “G” for green fuel is insufficient to capture the full range of environmental impacts of renewable fuel production and that it would be difficult for EPA to establish an appropriate cut-off point for determining which fuel qualified for a “G” designation. Several respondents suggested that EPA instead use a more continuous scale based on energy or lifecycle greenhouse gas emissions. A well designed voluntary labeling program could permit producers and blenders to distinguish their fuels in the marketplace and allow consumers to express preferences for “green” products through their fuel purchases. While such a program could be valuable to producers, blenders, and consumers, given the range of comments received on the topic, we believe it is important first to continue the dialogue with the various stakeholders to ensure that the program adequately addresses the issues raised prior to putting any such program in place. Thus we are not finalizing a voluntary labeling program. We will continue to investigate the issues surrounding a voluntary labeling program and the various ways in which it could be designed. In particular we are interested in further exploring methods to incorporate lifecycle impacts into a voluntary labeling program and consumer expectations for such “green” labeling. III. Complying With the Renewable Fuel Standard According to the Energy Act, the RFS program places obligations on individual parties such that the renewable fuel volumes shown in Table I.B-1 are used as motor vehicle fuel in the U.S. each year. To accomplish this, the Agency must calculate and publish a standard by November 30 of each year which is applicable to every obligated party. On the basis of this standard each obligated party determines the volume of renewable fuel that it must ensure is consumed as motor vehicle fuel. In addition to setting the standard, we must clarify who the obligated parties are and what volumes of gasoline are subject to the standard. Obligated parties must also know which renewable fuels are valid for RFS compliance purposes, and the relative values of each type of renewable fuel in terms of compliance. This section discusses how the annual standard is determined and which parties and volumes of gasoline will be subject to the requirements. Because renewable fuels are not produced or distributed evenly around the country, some obligated parties will have easier access to renewable fuels than others. As a result, the RFS program depends on a robust trading program. This section also describes all the elements of our trading program. A. What Is the Standard That Must Be Met? 1. How Is the Percentage Standard Calculated? Table I.B-1 shows the required total volume of renewable fuel specified in the Act for 2007 through 2012. The renewable fuel standard is based primarily on
(1)the 48-state gasoline consumption volumes projected by EIA (as the Act exempts Hawaii and Alaska, subject to their right to opt-in, as discussed in Section III.C.4), and
(2)the volume of renewable fuels required by the Act for the coming year. The renewable fuel standard will be expressed as a volume percentage of gasoline sold or introduced into commerce in the U.S., and will be used by each refiner, blender or importer to determine their renewable volume obligation. The applicable percentage is set so that if each regulated party meets the percentage and total gasoline consumption does not fall short of EIA projections then the total amount of renewable fuel used will meet the total renewable fuel volume specified in Table I.B-1. In determining the applicable percentage for a calendar year, the Act requires EPA to adjust the standard to prevent the imposition of redundant obligations on any person and to account for the use of renewable fuel during the previous calendar year by exempt small refineries, defined as refineries that process less than 75,000 bpd of crude oil. As a result, in order to be assured that the percentage standard will in fact result in the volumes shown in Table I.B-1, we must make several adjustments to what is otherwise a simple calculation. As stated, the renewable fuel standard for a given year is basically the ratio of the amount of renewable fuel specified in the Act for that year to the projected 48-state non-renewable gasoline volume for that year. While the required amount of total renewable fuel for a given year is provided by the Act, the Act requires EPA to use an EIA estimate of the amount of gasoline that will be sold or introduced into commerce for that year. The level of the percentage standard is reduced if Alaska, Hawaii, or a U.S. territory choose to participate in the RFS program, as gasoline produced in or imported into those states or territories would then be subject to the standard. Should any of these states or territories opt into the RFS program, the projected gasoline volume would increase above that consumed in the 48 contiguous states. In the proposal, we stated that EIA had indicated that the best estimation of the coming year's gasoline consumption is found in Table 5a (U.S. Petroleum Supply and Demand: Base Case) of the October issue of the monthly EIA publication Short-Term Energy Outlook which publishes quarterly energy projections. Commenters on this issue supported the use of the October issue of EIA's Short-Term Energy Outlook (STEO), Table 5a, for the purpose of estimating the next year's gasoline consumption, and we have used the October 2006 STEO values for estimating 2007 gasoline consumption for this final rule. The gasoline volumes in the STEO include renewable fuel use. As discussed below in Section III.C.1, the renewable fuel obligation does not apply to renewable blenders. Thus, the gasoline volume used to determine the standard must be the non-renewable portion of the gasoline pool, in order to achieve the volumes of renewables specified in the Act. In order to get a total non-renewable gasoline volume, we must subtract the renewable fuel volume from the total gasoline volume. EIA has indicated that the best estimation of the coming year's renewable fuel consumption is found in Table 11 (U.S. Renewable Energy Use by Sector: Base Case) of the October issue of the STEO. As with the gasoline projections discussed above, we have used the October 2006 STEO values for estimating 2007 renewable fuel values for this final rule. The Act exempts small refineries 7 from the RFS requirements until the 2011 compliance period. As discussed in Section III.C.3.a, as proposed, EPA is also exempting small refiners 8 from the RFS requirements until 2011, and is treating small refiner gasoline volumes the same as small refinery gasoline volumes. Since small refineries and small refiners are exempt from the program until 2011, EPA is excluding their gasoline volumes from the overall non-renewable gasoline volume used to determine the applicable percentage. EPA believes this is appropriate because the percentage standard should be based only on the gasoline subject to the renewable volume obligation. Because small refineries and small refiners are exempt (unless they waive exemption) only through the 2010 compliance period when the exemption ends, calculation of the standard for calendar year 2011 and beyond will include small refinery and small refiner volumes. 9 Using information from gasoline batch reports submitted to EPA, EIA data, and input from the California Air Resources Board regarding California small refiners, we are finalizing a small refiner exemption adjustment to the standard of a constant 13.5%, 10 consistent with the proposal. 7 Under the Act, small refineries are those with 75,000 bbl/day or less average aggregate daily crude oil throughput. 8 Small refiners are those entities who produced gasoline from crude oil in 2004, and who meet the crude processing capability (no more than 155,000 barrels per calendar day, bpcd) and employee (no more than 1500 people) criteria as specified in previous EPA fuel regulations. 9 As discussed in section III.C.3.a of this preamble, the small refinery exemption may be extended under 211(o)(9)(A)(ii) or
(B)of the Clean Air Act as amended by the Energy Policy Act. 10 “Calculation of the Small Refiner/Small Refinery Fraction for the Renewable Fuel Program,” memo to the docket from Christine Brunner, ASD, OTAQ, EPA September 2006. The Act requires that the small refinery adjustment also account for renewable fuels used during the prior year by small refineries that are exempt and do not participate in the RFS program. Accounting for this volume of renewable fuel would reduce the total volume of renewable fuel use required of others, and thus directionally would reduce the percentage standard. However, as discussed in the proposal, there are no such data available, the amount of renewable fuel that would qualify (i.e., that was used by exempt small refineries and small refiners but not used as part of the RFS program) is expected to be very small and would not significantly change the resulting percentage standard. Because whatever renewables small refiners and small refineries blend will be reflected as RINs available in the market, there is no need for a separate accounting of their renewable fuel use in the equation used to determine the standard. We thus proposed that this value be zero, and we are finalizing the equation as such. We also proposed not to include renewable fuel used in Alaska, Hawaii, or U.S. territories when subtracting renewable fuel volumes from the anticipated total gasoline volumes in EIA projections. The Act requires that the renewable fuel be consumed in the contiguous 48 states unless Alaska, Hawaii, or a U.S. territory opt-in. However, because renewable fuel produced in Alaska, Hawaii, and U.S. territories is unlikely to be transported to the contiguous 48 states, including their renewable fuel volumes in the calculation of the standard would not serve the purpose intended by the Act of ensuring that the statutorily required renewable fuel volumes are consumed in the 48 contiguous States. We are finalizing the exclusion of these areas' renewable fuel use as proposed. We stated that any deficit carryover from 2006 would increase the 2007 standard. Since renewable fuel use in 2006 exceeded the 2.78 percent default standard, there is no deficit to carry over to 2007. Beginning with the 2007 compliance period, when annual individual party compliance replaces collective compliance, any deficit is calculated for an individual party and is included in the party's Renewable Volume Obligation
(RVO)determination, as discussed in Section III.A.4. In summary, the total projected non-renewable gasoline volumes from which the annual standard is calculated is based on EIA projections of gasoline consumption in the contiguous 48 states, adjusted by a constant percentage of 13.5% to account for small refinery/refiner volume, with built-in correction factors to be used when and if non-contiguous states and territories opt-in to the program. If actual gasoline consumption were to exceed the EIA projection, the result would be that renewable fuel volumes will exceed the statutory requirements. Conversely, if actual gasoline consumption was less than the EIA projection for a given year, theoretically a renewable fuel shortfall could occur. However, our projections of renewable fuel use due to market demand would make a shortfall extremely unlikely regardless of the error in gasoline consumption projections. The following formula will be used to calculate the percentage standard: ER01MY07.056 Where: RFStd <sup>i</sup> = Renewable Fuel standard in year i, in percent. RFV <sup>i</sup> = Annual volume of renewable fuels required by section 211(o)(2)(B) of the Act for year i, in gallons. G <sup>i</sup> = Amount of gasoline projected to be used in the 48 contiguous states, in year i, in gallons. R <sup>i</sup> = Amount of renewable fuel blended into gasoline that is projected to be consumed in the 48 contiguous states, in year i, in gallons. GS <sup>i</sup> = Amount of gasoline projected to be used in Alaska, Hawaii, or a U.S. territory in year i if the state or territory opts-in, in gallons. RS <sup>i</sup> = Amount of renewable fuel blended into gasoline that is projected to be consumed in Alaska, Hawaii, or a U.S. territory in year i if the state or territory opts-in, in gallons. GE <sup>i</sup> = Amount of gasoline projected to be produced by exempt small refineries and small refiners in year i, in gallons (through 2010 only unless exemption extended under §§ 211(o)(9)(A)(ii) or (B)). Equivalent to 0.135*(G <sup>i</sup> −R <sup>i</sup> ). Cell <sup>i</sup> = Beginning in 2013, the amount of renewable fuel that is required to come from cellulosic sources, in year i, in gallons (250,000,000 gallons minimum). After 2012 the Act requires that the applicable volume of required renewable fuel specified in Table I.B-1 include a minimum of 250 million gallons that are derived from cellulosic biomass. As shown in Table III.A.2-1 below, we have estimated this value (250 million gallons) as a percent of an obligated party's production for 2013. Thus, an obligated party will be subject to two standards in 2013 and beyond, a non-cellulosic standard and a cellulosic standard. We are therefore also finalizing the following formula for calculating the cellulosic standard that is required beginning in 2013: ER01MY07.057 Where, except for RFCell <sup>i</sup> , the variable descriptions are as discussed above. The definition of RFCell <sup>i</sup> is: RFCell <sup>i</sup> = Renewable Fuel Cellulosic Standard in year i, in percent Note that after 2012 cellulosic RINs cannot be used to satisfy the non-cellulosic RFS standard (RFStd <sup>i</sup> ). The amount of renewable fuel that is required to come from cellulosic sources (Cell <sup>i</sup> ) is a fixed amount. We are not finalizing regulations that would specify the criteria under which a state could petition the EPA for a waiver of the RFS requirements, nor the ramifications of Agency approval of such a waiver in terms of the level or applicability of the standard. As discussed in the proposal, there was no clear way to include such a provision in the context of the program being finalized. As a result, the formula for the standard shown above does not include any components to account for Agency approval of a state petition for a waiver of the RFS requirements. Should EPA grant such a waiver in the future, it will determine at that time what adjustments to make to the standard. 2. What Are the Applicable Standards? As discussed in the proposal, EPA will set the percentage standard for each upcoming year based on the most recent EIA STEO projections, and using the other sources of information as noted above. EPA will publish the standard in the **Federal Register** by November 30 of the preceding year. The standards are used to determine the renewable volume obligation based on an obligated party's total gasoline production or import volume in a calendar year, January 1 through December 31. The percentage standards do not apply on a per gallon basis. An obligated party will calculate its Renewable Volume Obligation (discussed in Section III.A.4) using the annual standard. In the NPRM, we estimated the standards for 2007 and later using data available at the time and the formulas discussed above. 11 We have revised these values based on more recent data, and using EIA's October 2006 STEO gasoline and renewable fuel consumption projections. 12 In the proposal, we had used the lower heating value of ethanol for converting from Btu to gallons of ethanol for the purpose of calculating the standard. However, for this final rule, we have used the higher heating value of ethanol as recommended by commenters, to be consistent with EIA practices. 13 14 Variables related to state or territory opt-ins were set to zero since we do not have any information related to their participation at this time. As mentioned earlier, we estimate the small refinery and small refiner fraction to be 13.5%. The exemption for small refineries and small refiners ends at the end of the 2010 compliance period, unless extended as discussed in Section III.C.3.a. Based on all of these factors, the standard for 2007 is 4.02%. Projected values of the standard for 2008 and beyond are shown in Table III.A.2-1. 11 “Calculation of the Renewable Fuel Standard” memo to the docket from Christine Brunner, ASD, OTAQ, EPA, September 2006. 12 “Calculation of the Renewable Fuel Standard—Revised” memo to the docket from Christine Brunner, ASD, OTAQ, EPA, April 2007. 13 The higher (or gross or upper) heating value is used in all Btu calculations for EIA's Annual Energy Review and in related EIA publications (see discussion in EIA's Annual Energy Review, Appendix A, Thermal Conversion Factors). 14 The lower heating value
(LHV)is used to represent energy content in the context of setting Equivalence Values as described in Section III.B.4 because it more accurately reflects the energy available in the fuel to produce work. Table III.A.2-1.—Projected Standards Year Projected standard Cellulosic standard 2008 4.63% Not applicable. 2009 5.21% Not applicable. 2010 5.80% Not applicable. 2011 5.38% Not applicable. 2012 5.42% Not applicable. 2013+ 5.24% min. (non-cellulosic) 0.18% min. As discussed in Section II.A.5, for calendar year 2013 and thereafter, the applicable volumes will be determined in accordance with separate statutory provisions that include EPA coordination with the Departments of Agriculture and Energy, and a review of the program during calendar years 2006 through 2012. The Act specifies that this review consider the impact of the use of renewable fuels on the environment, air quality, energy security, job creation, and rural economic development, and the expected annual rate of future production of renewable fuels, including cellulosic ethanol. We intend to conduct another rulemaking as we approach the 2013 timeframe that would include our review of these factors. That rulemaking will present our conclusions regarding the appropriate applicable volume of renewable fuel for use in calculating the renewable fuel standard for 2013 and beyond. The program finalized by today's rule will continue to apply after 2012, though some elements may be modified in the rulemaking setting the standards for 2013 and beyond. Today's rule does not contain a mechanism for establishing a post-2012 standard. 3. Compliance in 2007 The Energy Act requires that EPA promulgate regulations to implement the RFS program, and if EPA did not issue such regulations then a default standard for renewable fuel use would apply in 2006. On December 30, 2005 we promulgated a direct final rule to interpret and implement the application of the statutory default standard of 2.78 percent in calendar year 2006 (70 FR 77325). However, the Act provides no default standard for any other year. In the NPRM we stated our expectation that, due to the limited time available for this rulemaking, we would be unable to publish the final rule and have it become effective by January 1, 2007. We discussed several ways that we could specify how, and for what time periods, the applicable standard and other program requirements would apply to regulated parties for gasoline produced during 2007. We discussed a collective compliance approach similar to that applied in 2006, as well as a “full year” approach that would have based the renewable volume obligation for each obligated party on all gasoline produced starting on January 1, 2007 regardless of the effective date of the rule. However, due to a number of issues with these approaches, we proposed a “prospective” approach in which the renewable fuel standard would be applied to only those volumes of gasoline produced after the effective date of the final rule. Essentially the renewable volume obligation for 2007 would be based on only those volumes of gasoline produced or imported by an obligated party prospectively from the effective date of the rulemaking forward, and renewable producers would not have to begin generating RINs and maintaining the necessary records until this same date. We received no comments supporting the alternative “full year” approach to 2007 compliance. However, several parties expressed a preference for either a collective compliance approach for 2007, or if not that then delaying implementation of the comprehensive program to January 1, 2008. They argued that regulated parties needed additional time to put into place the sophisticated RIN tracking systems that would be required. The additional time would also allow regulated parties to debug the systems, train personnel, and put support programs into place. The American Coalition for Ethanol also argued that the prospective approach did not guarantee that the total renewable fuel volumes required by the Act for 2007 would actually be used in 2007, whereas a collective compliance approach would. Parties in favor of a collective compliance approach argued that EPA has the authority to implement such an approach despite the fact that the Act does not explicitly give EPA this authority, and also argued that there was no need to include any form of credit carryover under a collective compliance approach. However, a number of refiners and their associations opposed a collective compliance approach to 2007 and expressed strong support for the proposed prospective approach. They argued that a start date at least 60 days from the date of publication of the final rule would provide sufficient time to obligated parties for making the necessary adjustments for compliance. They also argued that they should be afforded the opportunity to participate as soon as possible in the trading program, which the collective compliance approach used for 2006 would preclude for 2007. We continue to believe that a collective compliance approach is not appropriate for 2007. The Energy Act requires us to promulgate regulations that provide for the generation of credits by any person who over complies with their obligation. It also stipulates that a person who generates credits must be permitted to use them for compliance purposes, or to transfer them to another party. These credit provisions have meaning only in the context of an individual obligation to meet the applicable standard. Delaying a credit program until 2008 would mean the credit provisions have no meaning at all for 2007, since under a collective compliance approach no individual facility or company would be liable for meeting the applicable standard. Including a “collective” credit or deficit carryforward as part of a collective compliance program would also not fully implement the credit provisions of the Act. The prospective compliance approach, in contrast, not only provides obligated parties with the opportunity to generate credits, but also provides the industry with the certainty they need to comply and is relatively straightforward to implement. Rather than requiring the program to begin on the effective date of the rule as proposed (60 days following publication in the **Federal Register** ), we are finalizing a start date of September 1, 2007. From this date forward, the renewable fuel standard will be applicable to all gasoline produced or imported, and all renewable fuels produced or imported will have to be assigned a RIN. All regulated parties must be registered by this date, and the recordkeeping responsibilities will also begin. By setting such a date, industry will be able to plan with confidence to start complying upon signature of the rule, rather than having the start date depend upon the timing of publication of this final rule in the **Federal Register** . We recognize the concerns expressed in comments that time is needed to prepare Information Technology
(IT)systems to comply with the program. However, we believe that a September 1, 2007 start date will provide sufficient time. The final rule is in most respects consistent with the NPRM, and based on discussions with industry, plans for implementation are already underway. Furthermore, a September 1, 2007 start date will likely provide regulated parties some additional time to prepare in comparison to simply setting the start date as 60 days following publication of the rule. As stated in the NPRM, we recognize that the prospective approach to 2007 compliance will not guarantee by regulation that the total renewable fuel volumes required by the Act for 2007 would actually be used in 2007. However, current projections from the Energy Information Administration
(EIA)on the volume of renewable fuel expected to be produced in 2007 indicate that the Act's required volumes will be exceeded by a substantial margin due to the relative economic value of renewable fuels in comparison to gasoline. We are confident that the combined effect of the regulatory requirements for 2007 and the expected market demand for renewable fuels will lead to greater renewable fuel use in 2007 than is called for under the Act. Current renewable production already exceeds the rate required for all of 2007, and as discussed in Section VI, capacity is expected to continue to grow. Furthermore, refiners and importers are not required to meet any requirements under the Act until EPA adopts the regulations, and EPA is authorized to consider appropriate lead time in establishing the regulatory requirements. 15 Under this option we believe there will be reasonable lead-time for regulated parties to meet their 2007 compliance obligations. While no option before us is perhaps totally consistent with all of the provisions of the Act, we believe the rule as adopted does the best job possible given the circumstances of implementing all of the provisions of the Act for 2007. 15 The statutory default standard for 2006 is the one exception to this, since it directly establishes a renewable fuel obligation applicable to refiners and importers in the event that EPA does not promulgate regulations. 4. Renewable Volume Obligations In order for an obligated party to demonstrate compliance, the percentage standards described in Section III.A.2 which are applicable to all obligated parties must be converted into the volume of renewable fuel each obligated party is required to satisfy. This volume of renewable fuel is the volume for which the obligated party is responsible under the RFS program, and is referred to here as its Renewable Volume Obligation (RVO). The calculation of the RVO requires that the standard shown in Table III.A.2-1 for a particular compliance year be multiplied by the gasoline volume produced by an obligated party in that year. To the degree that an obligated party did not demonstrate full compliance with its RVO for the previous year, the shortfall is included as a deficit carryover in the calculation. The equation used to calculate the RVO for a particular year is shown below: RVO <sup>i</sup> = Std <sup>i</sup> × GV <sup>i</sup> + D <sup>i−1</sup> Where: RVO <sup>i</sup> = The Renewable Volume Obligation for the obligated party for year i, in gallons. Std <sup>i</sup> = The RFS program standard for year i, in percent. GV <sup>i</sup> = The non-renewable gasoline volume produced by an obligated party in year i, in gallons. D <sup>i−1</sup> = Renewable fuel deficit carryover from the previous year, in gallons. The Energy Act only permits a deficit carryover from one year to the next if the obligated party achieves full compliance with its RVO including the deficit carryover in the second year. Thus deficit carryovers could not occur two years in succession. They could, however, occur as frequently as every other year for a given obligated party. The calculation of an obligated party's RVO is necessarily retrospective, since the total gasoline volume that it produces in a calendar year will not be known until the year has ended. However, the obligated party will have an incentive to project gasoline volumes, and thus the RVO, throughout the year so that it can spread its efforts to comply across the entire year. Most refiners and importers will be able to project their annual gasoline production volumes with a minimum of uncertainty based on their historical operations, capacity, plans for facility downtimes, knowledge of gasoline markets, etc. Even if unforeseen circumstances (e.g., hurricane, unit failure, etc.) significantly reduced the production volumes in comparison to their projections, their RVO will likewise be reduced proportionally and their ability to comply with the RFS requirements will be only minimally affected. Each obligated party's projected RVO for a given year becomes more accurate as that year progresses, but the obligated party should nevertheless have a sufficiently accurate estimate of its RVO at the beginning of the year to allow it to begin its efforts to comply. B. What Counts as a Renewable Fuel in the RFS Program? Section 211(o) of the Clean Air Act defines “renewable fuel” and specifies many of the details of the renewable fuel program. The following section provides EPA's views and interpretations on issues related to what fuels may be counted towards compliance with the RVO, and how they are counted. 1. What Is a Renewable Fuel That Can Be Used for Compliance? The statutory definition of renewable fuel includes cellulosic ethanol and waste derived ethanol. It includes biodiesel, as defined in the Energy Act. 16 It also includes all motor vehicle fuels that are produced from biomass material such as grain, starch, oilseeds, animal, or fish materials including fats, greases and oils, sugarcane, sugar beets, tobacco, potatoes or other biomass (such as bagasse from sugar cane, corn stover, and algae and seaweed). In addition, it includes motor vehicle fuels made using a feedstock of natural gas if produced from a biogas source such as a landfill, sewage waste treatment plant, feedlot, or other place where decaying organic material is found. 16 As discussed below, for purposes of this rulemaking, the regulations separate “biodiesel” as defined in the Energy Act, into biodiesel (diesels that meet the Energy Act's definition and are a mono-alkyl ester) and renewable diesel (other diesels that meet the Energy Act's definition but are not mono-alkyl esters). According to the Act, the motor vehicle fuels must be used “to replace or reduce the quantity of fossil fuel present in a fuel mixture used to operate a motor vehicle.” Some motor vehicle fuels can be used in both motor vehicles or nonroad engines or equipment. For example, highway gasoline and diesel fuel are often used in both highway and off-highway applications. Compressed natural gas can likewise be used in either highway or nonroad applications. For purposes of the renewable fuel program, EPA considers a fuel to be a “motor vehicle fuel” and to be “a fuel mixture used to operate a motor vehicle,” based on its potential for use in highway and nonroad vehicles, without regard to whether it, in fact, is used in a highway vehicle application. EPA does not believe that the much more complex and costly regulatory scheme that would be needed to track motor vehicle fuel use versus off-road fuel use would be justified. (As discussed further below, heaters and boilers are not considered highway or nonroad engine applications and renewable fuel produced or imported specifically for use in such equipment is not valid for compliance purposes under the RFS program.) If it is a fuel that could be used in highway vehicles, it will satisfy these parts of the definition of renewable fuel, whether it is later used in highway or nonroad applications. This will allow a motor vehicle fuel that otherwise meets the definition to be counted towards a party's RVO without the need to track it to determine its actual application in a highway vehicle, and provided only that the producer does not know that the fuel will be used for a purpose other than highway and nonroad engine applications. This is also consistent with the requirement that EPA base the renewable fuel obligation on estimates of the entire volume of gasoline consumed, without regard to whether it is used in highway or nonroad applications. Renewable fuel as defined, may be made from a number of different types of feedstocks. For example, the Fisher-Tropsch process can use methane gas from landfills as a feedstock, to produce diesel or gasoline. Vegetable oil made from oilseeds such as rapeseed or soybeans can be used to make biodiesel or renewable diesel. Methane, made from landfill gas (biogas) can be used to make methanol, or can be used directly as a fuel in vehicles with engines designed to run on compressed natural gas. Also, some vegetable oils or animal fats can be processed in distillation columns in refineries to make gasoline; as such, the renewable feedstock serves as a “renewable crude,” and the resulting gasoline or diesel product would be a renewable fuel. This last example is discussed in further detail in Section III.B.3 below. As this discussion shows, the definition of renewable fuel in the Act is broad in scope, and covers a wide range of fuels. While ethanol is used primarily in combination with gasoline, the definition of renewable fuel in the Act is not limited to fuels that can be blended with gasoline. Various fuels that meet the definition of renewable fuel can be used in their neat form, such as ethanol, biodiesel, methanol or natural gas. Others, including ethanol may be used to produce a gasoline blending component (such as ETBE). At the same time, the RFS regulatory program is to “ensure that gasoline sold or introduced into commerce * * * contains the applicable volume of renewable fuel.” This applicable volume is specified as a total volume of renewable fuel on an aggregate basis. Congress also clearly specified that one renewable fuel, biodiesel, could be counted towards compliance even though it is not a gasoline component, and does not directly displace or replace gasoline. The Act is unclear on whether other fuels that meet the definition of renewable fuel, but are not used in gasoline, could also be used to demonstrate compliance towards the aggregate national use of renewable fuels. EPA interprets the Act as allowing regulated parties to demonstrate compliance based on any fuel that meets the statutory definition for renewable fuel, whether it is directly blended with gasoline or not. This would include neat alternative fuels such as ethanol, methanol, and natural gas that meet the definition of renewable fuel. This is appropriate for several reasons. First, it promotes the use of all renewable fuels, which will further the achievement of the purposes behind this provision. Congress did not intend to limit the program to only gasoline components, as evidenced by the provision for biodiesel, and the broad definition of renewable fuel evidences an intention to address more renewable fuels than those used with gasoline. Second, in practice EPA expects that the overwhelming volume of renewable fuel used to demonstrate compliance with the renewable fuel obligation would still be ethanol blended with gasoline. Finally, as discussed later, EPA's compliance program is based on assigning volumes at the point of production, and not at the point of blending into motor vehicle fuel. This interpretation avoids the need to track renewable fuels downstream to ensure they are blended with gasoline and not used in their neat form; the gasoline that is used in motor vehicles is reduced by the presence of renewable fuels in the gasoline pool whether they are blended with gasoline or not. Comments received on this interpretation were favorable towards it. EPA continues to believe, therefore, that this approach is consistent with the intent of Congress and is a reasonable interpretation of the Act. One commenter indicated that a logical extension of this reasoning would provide that renewable fuel that could be used in motor vehicles is still a renewable fuel under the Act when used by renewable fuel producers in a boiler or heater. EPA disagrees. The term “renewable fuel” means “motor vehicle fuel that * * * is used to replace or reduce the quantity of fossil fuel present in a fuel mixture used to operate a motor vehicle.” We believe that all but a trivial quantity of renewable fuels that can be used in motor vehicles will ultimately be used as motor vehicle fuel. Producers of ethanol biodiesel and other products that can be used as motor vehicle fuel can generally assume, therefore, that their products will be used in that way, and can assign RINs to their product without tracking its ultimate use. However, renewable fuel used onsite in a boiler or heater by a renewable fuel producer clearly is not a motor vehicle fuel used to replace or reduce the quantity of fossil fuel present in a fuel mixture used to operate a motor vehicle. Under the Act, renewable fuel includes “cellulosic biomass ethanol” and “waste derived ethanol”, each of which is defined separately. Ethanol can be cellulosic biomass ethanol in one of two ways, as described below. a. Ethanol Made From a Cellulosic Feedstock The simplest process of producing ethanol is by fermenting sugar in sugar cane or beets, but ethanol can also be produced from starch in corn and other feedstocks by first converting the starch to sugar. Ethanol can also be produced from complex carbohydrates, such as the cellulosic portion of plants or plant products. The cellulose is first converted to sugars (by hydrolysis); then the same fermentation process is used as for sugar to make ethanol. Cellulosic feedstocks (composed of cellulose and hemicellulose) are currently more difficult and costly to convert to sugar than are starches. While the cost and difficulty are a disadvantage, the cellulosic process offers the advantage that a wider variety of feedstocks can be used. Ultimately with more feedstocks available from which to make ethanol more volume of ethanol can be produced. The Act provides the definition of cellulosic biomass ethanol, which states: “The term ‘cellulosic biomass ethanol’ means ethanol derived from any lignocellulosic or hemicellulosic matter that is available on a renewable or recurring basis, including:
(i)Dedicated energy crops and trees;
(ii)Wood and wood residues;
(iii)Plants;
(iv)Grasses;
(v)Agricultural residues;
(vi)Animal wastes and other waste materials, and
(viii)Municipal solid waste.” Examples of cellulosic biomass source material include rice straw, switch grass, and wood chips. Ethanol made from these materials would qualify under the definition as cellulosic ethanol. In addition to the above sources of feedstocks for cellulosic biomass ethanol, the Act's definition also includes animal waste, municipal solid wastes, and other waste materials. “Other waste materials” generally includes waste material such as sewage sludge, waste candy, and waste starches from food production, but for purposes of the definition of cellulosic ethanol discussed in III.B.1.b below, it can also mean waste heat obtained from an off-site combustion process. Although the definitions of “cellulosic biomass ethanol” and “waste derived ethanol” both include animal wastes and municipal solid waste in their respective lists of covered feedstocks, there remains a distinction between these types of ethanol. If the animal wastes or municipal solid wastes contain cellulose or hemicellulose, the resulting ethanol can be termed “cellulosic biomass ethanol.” If the animal wastes or municipal solid wastes do not contain cellulose or hemicellulose, then the resulting ethanol is labeled “waste derived ethanol.” This is discussed further in Section III.B.1.c below. b. Ethanol Made From Any Feedstock in Facilities Using Waste Material To Displace 90 Percent of Normal Fossil Fuel Use The definition of cellulosic biomass ethanol in the Act also provides that ethanol made at any facility—regardless of whether cellulosic feedstock is used or not—may be defined as cellulosic if at such facility “animal wastes or other waste materials are digested or otherwise used to displace 90 percent or more of the fossil fuel normally used in the production of ethanol.” The statutory language suggests that there are two methods through which “animal and other waste materials” may be considered for displacing fossil fuel. The first method is the digestion of animal wastes or other waste materials. EPA has interpreted the term “digestion” to mean the conversion of animal or other wastes into methane, which can then be combusted as fuel. We base our interpretation on the practice in industry of using anaerobic digesters to break down waste products such as manure into methane. Anaerobic digestion refers to the breakdown of organic matter by bacteria in the absence of oxygen, and is used to treat waste to produce renewable fuels. We note also that the digestion of animal wastes or other waste materials to produce the fuel used at the ethanol plant does not have to occur at the plant itself. Methane made from animal or other wastes offsite and then purchased and used at the ethanol plant would also qualify. The second method is suggested by the term “otherwise used” which we interpret to mean
(1)the direct combustion of the waste materials as fuel at an ethanol plant, or
(2)the use of thermal energy that itself is a waste product; e.g., waste heat that is obtained from an off-site combustion process such as a neighboring plant that has a furnace or boiler from which the waste heat is captured. With respect to the first meaning, “other waste materials” includes but is not limited to waste materials from tree farms (tops, branches, limbs, etc.), or waste materials from saw mills (sawdust, shavings and bark) as well as other vegetative waste materials such as corn stover, or sugar cane bagasse, that could be used as fuel for gasifier/boiler units at ethanol plants. Since these materials are not also used as a feedstock to starch-based ethanol plants, they are truly waste materials. Although these waste materials conceivably could be feedstocks to a cellulosic ethanol plant, their use in that manner is sufficiently challenging at the current time that EPA believes that such use does not subvert the intent of the definition. 17 Since corn kernels can readily be used as a feedstock in a typical ethanol production facility, their use as a fuel for gasified/boiler units at a corn ethanol plant would not be considered use of “other waste material” for purposes of the definition of cellulosic biomass ethanol. 17 On the other hand, wood from plants or trees that are grown as an energy crop may not qualify as a waste-derived fuel in an ethanol facility because such wood would not qualify as waste materials under this portion of the definition. Under the definition of renewable fuels and cellulosic biomass ethanol, however, such wood material could serve as a feedstock in a cellulosic ethanol plant, since these definitions do not restrict such feedstock to waste materials only. Regarding the use of waste heat as a source of thermal energy, we note that there may be situations in which an off-site furnace, boiler or heater creates excess or waste heat that is not used in the process for which the thermal energy is employed. For example, a glass furnace generates a significant amount of waste heat that often goes unused. We have therefore included in the regulatory definition of cellulosic biomass ethanol waste heat generated from off-site sources in the definition of “other waste materials” that can be used to displace 90% of the fossil fuel otherwise used at an ethanol production facility. Several commenters argued that because the source of the waste heat is ultimately a fossil fuel in most cases that it should not be considered an “other waste material”. The Agency recognizes that fossil fuel is ultimately the source of most waste heat, but it is also the case that waste heat that is uncaptured represents a loss of energy that could otherwise displace fossil fuel use elsewhere. Specifically, waste heat used at an ethanol plant would result in displacement of fossil fuel use at the plant. In writing the proposed rule, we were aware of the concern raised by the commenters and therefore proposed to restrict waste heat to off-site sources only. We believe that this approach minimizes the concern. We disagree with another commenter that such restriction would create a perverse incentive for facilities near ethanol plants to oversize its combustion units to sell waste heat to the neighboring ethanol facilities where it would be used to displace fossil fuel. It is highly unlikely that businesses would incur the additional expense of building an oversized combustion unit for the sale of waste heat. Also, the 2.5 gallon value given for one gallon of cellulosic ethanol as provided by the Act extends only through 2012. Any additional market value for waste heat used to qualify ethanol as cellulosic would therefore be of relatively short duration and not likely to warrant investment in oversized combustion units. 18 18 The term “other waste materials” is also included in the portions of the definitions of “cellulosic biomass ethanol” and “waste-derived ethanol” that identify feedstocks. The inclusion of off-site generated waste heat in the definition of “other waste materials”, however, applies only to the portion of the definition of cellulosic biomass ethanol that relates to displacement of fossil fuels, and does not apply to the term “other waste materials” as otherwise used in these definitions. The term “fossil fuel normally used in the production of ethanol” means fossil fuel used at the facility in the ethanol production process itself, rather than other phases such as trucks transporting product, and fossil fuel used to grow and harvest the feedstock. Therefore the diesel fuel that trucks consume in hauling wood waste from sawmills to the ethanol facility would not be counted in determining whether the 90% displacement criterion has been met. We are interpreting it in this way because we believe the accounting of fuel use associated with transportation and other life cycle activities would be extremely difficult and in many cases impossible. 19 19 In Section IX of today's preamble we discuss our analysis of the lifecycle fuel impacts of the RFS rule, with respect to greenhouse gas
(GHG)emissions. While we do account for fuel used in hauling materials to ethanol plants in our analysis, we are using average nationwide values, rather than data collected for individual plants. Based on the operation of ethanol plants, we are viewing this definition to apply to waste materials used to produce thermal energy rather than electrical energy. Electrical usage at ethanol plants is used for lights and equipment not directly related to the production of ethanol. Also, the calculation of fossil fuel used to generate such electrical usage would be difficult because it is not always possible to track the source of electricity that is purchased off-site. Therefore, the final regulations consider displacement of 90 percent of fossil fuels at the ethanol plant to mean those fuels consumed on-site and that are used to generate thermal energy used to produce ethanol. One commenter suggested that electricity from cogeneration (i.e., combined heat and power) units be considered in determining the percentage of fossil fuel use that is displaced. The commenter claims that allowing consideration of electricity use would provide an incentive for cogeneration to be used at ethanol plants. Our findings regarding the use of electricity at ethanol plants remain the same—that is, it is not used as part of the heat source in ethanol production for economic reasons. We note also that the commenter did not present any evidence to the contrary. As such, we continue to maintain that electricity is not “normally used in the production of ethanol” and we are therefore only considering the displacement of fossil fuels associated with thermal energy at the plant. Owners who claim their product qualifies as cellulosic biomass ethanol based on the 90 percent fossil fuel displacement through the use of waste materials (i.e., animal wastes, and other waste materials) are required under today's rule to keep records of fuel (waste-derived and fossil fuel) used for thermal energy for verification of their claims. They will also be required to track the fossil fuel equivalent of any off-site generated waste heat that is captured and which displaces fossil fuel used in the ethanol production process. Since such waste heat would typically be purchased through agreement with the off-site owner, we do not feel it burdensome for owners to track such information. Owners will therefore calculate the amount of energy in Btu's associated with waste-derived fuels (including the fossil fuel equivalent waste heat), and divided by the total energy in Btus used to produce ethanol in a given year. Ethanol produced from such facilities will get the benefit of the 2.5 ratio. (Section III.D.3.e discusses the requirements for owners of facilities that claim to have produced cellulosic ethanol under the 90 percent displacement provision, but which fail to meet those requirements.) c. Ethanol That Is Made From the Non-Cellulosic Portions of Animal, Other Waste, and Municipal Waste “Waste derived ethanol” is defined in the Act as ethanol derived from “animal wastes, including poultry fats and poultry wastes, and other waste materials; * * * or municipal solid waste.” Both animal wastes and municipal solid waste are also listed as allowable feedstocks for the production of “cellulosic biomass ethanol.” When such feedstocks do not contain cellulose, however, the resulting ethanol is waste derived. Both waste-derived and cellulosic ethanol both are considered equivalent to 2.5 gallons of renewable fuel when determining compliance with the renewable volume obligation. d. Foreign Producers of Cellulosic and Waste-Derived Ethanol Some commenters stated that foreign ethanol producers should not be able to have their cellulosic or waste-derived ethanol treated in the same manner as domestic cellulosic or waste-derived ethanol under the RFS program because of the difficulty in verifying their compliance with the provisions discussed above. Today's rule allows such producers to participate, provided they meet the requirements discussed in Section IV.D.2. of the preamble. The requirements for foreign producers of cellulosic or waste-derived ethanol are different than for domestic producers and allow for verification of compliance. 2. What Is Biodiesel? The Act states that “The term ‘renewable fuel’ includes * * * biodiesel (as defined in section 312(f)) of the Energy Policy Act of 1992.” This definition, as modified by Section 1515 of the Energy Act states: The term “biodiesel” means a diesel fuel substitute produced from nonpetroleum renewable resources that meets the registration requirements for fuels and fuel additives established by the Environmental Protection Agency under section 7545 of this title, and includes biodiesel derived from animal wastes, including poultry fats and poultry wastes, and other waste materials, or municipal solid waste and sludges and oils derived from wastewater and the treatment of wastewater. This definition of biodiesel would include both mono-alkyl esters which meet the current ASTM specification D-6751-07 20 (the most common meaning of the term “biodiesel”) that have been registered with EPA, and any non-esters that are intended for use in engines that are designed to run on conventional, petroleum-derived diesel fuel, have been registered with the EPA, and are made from any of the feedstocks listed above. 20 In the event that the ASTM specification D-6751 is succeeded with an updated specification in the future, EPA may revise the regulations accordingly at such time. Regulations cannot be promulgated that only reference “the most recent version” of an ASTM standard, since doing so would place the American Society for Testing and Materials in the position of a regulatory body. To implement the above definition of biodiesel in the context of the RFS rulemaking while still recognizing the unique history and role of mono-alkyl esters meeting ASTM D-6751, we have divided the Act's definition of biodiesel into two separate parts: Biodiesel (mono-alkyl esters) and non-ester renewable diesel. The combination of “biodiesel (mono-alkyl esters)” and “non-ester renewable diesel” in the regulations fulfills the Act's definition of biodiesel. Commenters supported EPA's approach in defining biodiesel in this manner. a. Biodiesel (Mono-Alkyl Esters) Under today's rule, the term “biodiesel (mono-alkyl esters)” means a motor vehicle fuel which:
(1)Meets the registration requirements for fuels and fuel additives established by the Environmental Protection Agency under section 7545 of this title (Clean Air Act Section 211);
(2)is a mono-alkyl ester;
(3)meets ASTM specification D-6751-07;
(4)is intended for use in engines that are designed to run on conventional, petroleum-derived diesel fuel, and
(5)is derived from nonpetroleum renewable resources. b. Non-Ester Renewable Diesel The term “non-ester renewable diesel” means a motor vehicle fuel which:
(1)Meets the registration requirements for fuels and fuel additives established by the Environmental Protection Agency under section 7545 of this title (Clean Air Act Section 211);
(2)is not a mono-alkyl ester;
(3)is intended for use in engines that are designed to run on conventional, petroleum-derived diesel fuel, and
(4)is derived from nonpetroleum renewable resources. Current examples of a non-ester renewable diesel include: “Renewable diesel” produced by the Neste or UOP process, or diesel fuel produced by processing fats and oils through a refinery hydrotreating process. 3. Does Renewable Fuel Include Motor Fuel That Is Made From Coprocessing a Renewable Feedstock With Fossil Fuels? Renewable fuels can be produced by processing biologically derived wastes such as animal fats, as well as other nonpetroleum based feedstocks in a traditional refinery—that is, a refinery that normally uses crude oil or other fossil fuel-based blendstocks as feeds to processing units. Such wastes are pre-processed so that they are in liquid form to enable their further processing in units at a traditional refinery. In the proposed rule, we defined such feedstocks as “biocrudes” and included a discussion on how the fuels resulting from these feedstocks should be counted. Our basic approach remains the same. We have changed the term “biocrudes” to “renewable crudes”, since we believe it is more accurate. We are providing additional discussion in this preamble on how renewable fuels are made from renewable crudes. The fuels resulting from the co-processing of the pre-processed liquid form of these renewable crudes (i.e., those feedstocks listed in the definition of “renewable fuel” and, for biodiesel, in the statutory definition of “biodiesel”) in a traditional refinery are themselves indistinguishable from the gasoline and diesel products produced from crude oil. As such, the treatment of any resulting renewable fuel presents a particular complication in terms of RFS program compliance—namely, if such fuels are indistinguishable from gasoline and diesel produced from crude oil feedstocks, how are the volumes to be measured? Also, some renewable feedstocks are used to produce renewable diesel (discussed in Section III.B.2 above). In other circumstances renewable feedstocks are processed in dedicated facilities or units—that is, in either
(1)facilities other than refineries that process fossil fuels,
(2)equipment located within a traditional refinery but which is dedicated to renewable feedstocks, or
(3)equipment located within a traditional refinery that processes renewable and conventional feedstocks but solely for the production of motor vehicle fuels. The processing approach for the renewable feedstock dictates whether the resulting fuel is distinguishable from crude oil-based fuels by virtue of its being made and stored separately from fossil fuels as discussed in further detail below. Therefore, our method for counting renewable fuels made from renewable feedstocks differ based on how the renewable feedstock is processed a. Definition of “Renewable Crudes” and “Renewable Crude-Based Fuels” Under some circumstances renewable feedstocks can be preprocessed into a liquid that is similar to petroleum-based feedstocks used in traditional refineries. We are classifying such liquids as “renewable crudes,” and any motor vehicle fuel that is made from such liquids is defined broadly as “renewable crude-based fuel”. There are three approaches that can be taken to making renewable fuels from renewable crudes. The first would include gasoline or diesel products resulting from the processing of renewable crudes in production units within refineries that simultaneously process crude oil and other petroleum based feedstocks. In these cases, the final product consists of a mixture of renewable fuel and fossil-based fuel, and may include both motor vehicle fuel and non-motor vehicle fuel. The second approach would include diesel and other products resulting from processing renewable crudes at a stand-alone facility that does not process any fossil fuels, or at a facility dedicated to renewable crudes within a traditional refinery. 21 In this case, a batch of renewable crude used as feedstock to a production unit would replace crude oil or other petroleum based feedstocks which ordinarily would be the feedstock in that process unit. The third approach would be non-ester renewable diesel fuel produced by processing fats and oils through a refinery hydrotreating process. All three approaches can produce renewable fuel that is valid for compliance purposes under the RFS program, but the measurement of volumes produced and/or their associated Equivalence Values may differ. 21 Renewable crude-based fuels will need to be registered under the provisions contained in 40 CFR 79 Part 4 before they can be sold commercially. b. How Are Renewable Crude-Based Fuel Volumes Measured? As discussed above, some renewable feedstocks are processed in facilities other than refineries, or in equipment located within a traditional refinery but which is dedicated to renewable feedstocks. The resulting product is “renewable diesel” (and such units may in the future also produce “renewable gasoline” though none is currently made in such dedicated facilities). In other situations, renewable crudes are coprocessed along with crude oils in traditional refineries, resulting in gasoline or diesel products that may be combinations of renewable and non-renewable fuels. In the case of renewable crude coprocessed with fossil fuels in refineries, we are assuming that all of the renewable crude used as a feedstock in a refinery unit will end up as a renewable crude-based fuel that is valid for RFS compliance purposes. We are taking this approach because renewable crudes that are processed through distillate hydrotreaters are first pre-processed so that they are in liquid form, and such liquid produces diesel fuel in volumes approximately equal to the amount that is input to the hydrotreater. We are assuming that renewable crudes could also be processed in other process units at refineries to make gasoline. The renewable crude processed at a refinery is functionally equivalent to crude oil, and the end products (gasoline and/or diesel) are indistinguishable from products made from crude oil. Thus, rather than requiring the refiner to document what portion of the renewable crude-based fuel is renewable fuel, we are requiring that the volume of the renewable crude itself count as the volume of renewable fuel produced for the purposes of determining the volume block codes that are in the RIN (discussed in further detail in Section III.D). 22 The general counting procedure for renewable crude-based fuels that are not derived through coprocessing with fossil fuels is that the volumes of renewable fuel produced are measured directly, and an appropriate Equivalence Value is assigned according to the methodology discussed in Section III.B.4. 22 We are considering the volumes of renewable crude itself, not the feedstocks that are made into renewable crude. 4. What Are “Equivalence Values” for Renewable Fuel? One question that EPA needed to address in developing the regulations was how to count volumes of renewable fuel in determining compliance with the renewable volume obligation. The Act stipulates that every gallon of waste-derived ethanol and cellulosic biomass ethanol should count as if it were 2.5 gallons for RFS compliance purposes. The Act does not stipulate similar values for other renewable fuels, but as described below we believe it is appropriate to do so. We are requiring that the “Equivalence Values” for renewable fuels other than those for which specific values are set forth in the Act be based on their energy content in comparison to the energy content of ethanol, adjusted as necessary for their renewable content. The result is an Equivalence Value for corn ethanol of 1.0, for biobutanol of 1.3, for biodiesel (mono alkyl ester) of 1.5, and for non-ester renewable diesel of 1.7. However, the methodology can be used to determine the appropriate equivalence value for any other potential renewable fuel as well. This section describes why the use of the Equivalence Value approach in today's rule is appropriate under the Act, and our conclusions regarding the possible future use of lifecycle analyses as the basis of Equivalence Values. a. Authority Under the Act To Establish Equivalence Values We are requiring that Equivalence Values be assigned to every renewable fuel to provide an indication of the number of gallons that can be claimed for compliance purposes for every physical gallon of renewable fuel. An Equivalence Value of 1.0 means that every physical gallon of renewable fuel counts as one gallon for RFS compliance purposes. An Equivalence Value greater than 1.0 means that every physical gallon of renewable fuel counts as more than one gallon for RFS compliance purposes, while a value less than 1.0 counts as less than one gallon. We have interpreted the Act as allowing us to develop Equivalence Values according to the methodology discussed below. We believe that the use of Equivalence Values based on energy content in comparison to the energy content of ethanol is consistent with the intent of Congress to treat different renewable fuels differently in different circumstances, and to provide incentives for use of renewable fuels in certain circumstances, as evidenced by those specific circumstances addressed by Congress. The Act has several provisions that provide for mechanisms other than straight volume measurement to determine the value of a renewable fuel in terms of RFS compliance. For example, 1 gallon of cellulosic biomass or waste derived ethanol is to be treated as 2.5 gallons of renewable fuel. EPA is also required to establish an “appropriate amount of credits” for biodiesel, and to provide for “an appropriate amount of credit” for using more renewable fuels than are required to meet your obligation. EPA is also to determine the “renewable fuel portion” of a blending component derived from a renewable fuel. These statutory provisions provide evidence that Congress did not limit this program solely to a straight volume measurement of gallons in the context of the RFS program. In response to the NPRM, some commenters supported our view that the Act provides sufficient context and direction to permit the use of Equivalence Values, while other commenters opposed this view. Some parties commented that the methodology proposed in the NPRM did not go far enough. These parties argued that instead of energy content, EPA should be using lifecycle impacts to set the Equivalence Values. Lifecycle analyses are discussed in more detail in Section III.B.4.c. Parties that opposed our proposed approach to Equivalence Values argued that since the Act did not explicitly give EPA the authority to set Equivalence Values for renewable fuels other than cellulosic biomass ethanol and waste-derived ethanol, EPA had no authority to do so. In their view, the explicit inclusion of a 2.5 credit value for cellulosic and waste-derived ethanol and the omission of any credit values for other renewables fuels should be taken as evidence that Congress intended all other renewable fuels to have Equivalence Values of 1.0. We disagree that our discretion is so strictly limited. The Act specifically gave EPA the authority to determine an “appropriate” credit for biodiesel, and also establishes a 2.5 value for cellulosic biomass ethanol and waste-derived ethanol. As ethanol and biodiesel were likely the two primary renewable fuels envisioned in the near-term under the Act, it would seem normal for Congress to have focused on these. However, Congress also clearly allowed for other renewable fuels to participate in the RFS program, and it is appropriate for EPA to consider how they should be treated under the Act. Furthermore, in addition to the Act's direction that EPA determine an appropriate level of credit for biodiesel, the Act also directs EPA to determine the “appropriate” amount of credit for renewable fuel use in excess of the required volumes, and to determine the “renewable fuel portion” of a blending component derived from a renewable fuel. These statutory provisions lend further support to our belief that Congress did not limit the RFS program solely to a straight volume measurement of gallons. Having concluded that it is appropriate to determine an appropriate level of credit for biodiesel based on energy content as compared to ethanol, EPA is using a consistent approach for other types of renewable fuels for which a specific statutory credit value is not prescribed. Another reason given by parties opposing our approach to Equivalence Values was that Equivalence Values higher than 1.0 would result in actual volumes of renewable fuel being less than the volumes required by the Act. Although it is true that the Act specifies the annual volumes of renewable fuel that the program must require and directs EPA to promulgate regulations ensuring that gasoline sold each year “contains the applicable volume of renewable fuel,” the Act also contains language that makes the achievement of those volumes imprecise. For instance, the deficit carryover provision allows any obligated party to fail to meet its RVO in one year if it meets the deficit and its RVO in the next year. If many obligated parties took advantage of this provision, it could result in the nationwide total volume obligation for a particular calendar year not being met. In addition, the calculation of the renewable fuel standard is based on projected nationwide gasoline volumes provided by EIA (see Section III.A). If the projected gasoline volume falls short of the actual gasoline volume in a given year, the standard will fail to create the demand for the full renewable fuel volume required by the Act for that year. The Act contains no provision for correcting for underestimated gasoline volumes, and as a result the volumes required by the Act may not be consumed in use. Some commenters disagreed with our belief that there will only be very limited additional situations where an Equivalence Value other than 1.0 is used. They expressed concern that the provision for Equivalence Values will interfere with meeting the total national volume goals for usage of renewable fuel. While in the long term we agree that renewable fuels with an Equivalence Value greater than 1.0 may grow to become a larger portion of the renewable fuel pool, we do not believe that this is likely to be the case before 2013, the time period when the statute specifies the overall national volumes. EPA will be issuing a new rule prior to 2013, and can reconsider its approach to Equivalence Values for renewable fuel at that time if it is appropriate to do so. For instance, EIA projects that biodiesel volumes will reach 300 million gallons by 2012. With the Equivalence Value of 1.5 that we are finalizing today, this means that the 7.5 billion gallons required by the Act for 2012 could be met with 7.35 billion gallons of renewable fuel. However, this result is well within the variability in actual volumes resulting from the other statutory provisions described above, and would still result in 7.5 billon gallons of ethanol-equivalent (in terms of energy content) renewable fuel being consumed. Congress explicitly recognized the expected use of credits for biodiesel, as it did for cellulosic ethanol. By requiring or authorizing EPA to assign credit values for such products, Congress recognized that the national volumes specified in the Act would not necessarily be met on a gallon per gallon basis. For the very limited number of other renewable fuels not covered by these express statutory provisions, assigning an equivalence value is consistent with this overall approach. Moreover, EIA is projecting that the total volume of renewable fuel will exceed the Act's requirements by a substantial margin due primarily to the favorable economics of ethanol in comparison to gasoline. Under such projections, the existence of renewable fuels with Equivalence Values higher than 1.0 will have no impact on the demand for renewable fuel. Finally, the Act also contains language indicating that EPA has flexibility in determining how various renewable fuels should count towards meeting the required annual volumes. For instance, valid renewable fuels are defined as those that “replace or reduce the quantity of fossil fuel present in a fuel mixture used to operate a motor vehicle.” Fossil fuels such as gasoline or diesel are only replaced or reduced to the degree that the energy they contain is replaced or reduced. We do not believe it would be appropriate to treat a renewable fuel with very low volumetric energy content as being equivalent to a renewable fuel with very high volumetric energy content, since the impact on motor vehicle fossil fuel use is very different for these two renewable fuels. The use of Equivalence Values based on volumetric energy content helps to achieve this goal. A case in point would be butanol. It is produced from the same feedstocks as ethanol (i.e., starch crops such as corn) in a similar process. However, it results in an alcohol with a higher volumetric energy content than ethanol. If we were to give butanol an Equivalence Value of 1.0, it would provide an economic disincentive for corn to be used to produce butanol instead of ethanol. As a result, we continue to believe that the assignment of Equivalence Values other than 1.0 to some renewable fuels is a reasonable way for the RFS program to establish “appropriate” credit values while also ensuring that the Act's volume obligations, read together with the Act's directions regarding credit values towards fulfillment of that obligation, are satisfied. This approach is consistent with the way Congress treated the various specific circumstances noted above, and thus is basically a continuation of that process. b. Energy Content and Renewable Content as the Basis for Equivalence Values To appropriately account for the different energy contents of different renewable fuels as well as the fact that some renewable fuels actually contain some non-renewable content, we are requiring that Equivalence Values be calculated using both the renewable content of a renewable fuel and its energy content. This section describes the calculation methodology for Equivalence Values. In order to take the energy content of a renewable fuel into account when calculating the Equivalence Values, we must identify an appropriate point of reference. Ethanol is a reasonable point of reference as it is currently the most prominent renewable fuel in the transportation sector, and it is likely that the authors of the Act saw ethanol as the primary means through which the required volumes would be met in at least the first years of the RFS program. By comparing every renewable fuel to ethanol on an equivalent energy content basis, each renewable fuel is assigned an Equivalence Value that precisely accounts for the amount of petroleum in motor vehicle fuel that is reduced or replaced by that renewable fuel in comparison to ethanol. To the degree that corn-based ethanol continues to dominate the pool of renewable fuel, this approach allows actual volumes of renewable fuel to be consistent with the volumes required by the Act. Equivalence Values also account for the renewable content of renewable fuels, since the presence of any non-renewable content impairs the ability of the renewable fuel to replace or reduce the quantity of fossil fuel present in a fuel mixture used to operate a motor vehicle. The Act specifically states that only the renewable fuel portion of a blending component should be considered part of the applicable volume under the RFS program. As described in more detail below, we have interpreted this to mean that every renewable fuel should be evaluated at the molecular level to distinguish between those molar fractions that were derived from a renewable feedstock, versus those molar fractions that were derived from a fossil fuel feedstock. Along with energy content in comparison to ethanol, the relative energy fraction of renewable versus non-renewable content is thus used directly as the basis for the Equivalence Value. We are requiring that the calculation of Equivalence Values simultaneously take into account both the renewable content of a renewable fuel and its energy content in comparison to denatured ethanol. To accomplish this, we are requiring the following formula: EV = (R <sup>RF</sup> / R <sup>Eth</sup> ) × (EC <sup>RF</sup> / EC <sup>Eth</sup> ) Where: EV = Equivalence Value for the renewable fuel. R <sup>RF</sup> = Renewable content of the renewable fuel, in percent of molecular energy. R <sup>Eth</sup> = Renewable content of denatured ethanol, in percent of molecular energy. EC <sup>RF</sup> = Energy content of the renewable fuel, in Btu per gallon (LHV). EC <sup>Eth</sup> = Energy content of denatured ethanol, in Btu per gallon (LHV). Instead of the higher heating value, the lower heating value
(LHV)is used to represent energy content because it more accurately reflects the energy available in the fuel to produce work. R is a measure of that portion of the renewable fuel molecules which can be considered to have come from a renewable source. Since R (that is, R <sup>RF</sup> and R <sup>Eth</sup> ) is being combined with relative energy content in the formula above, the value of R cannot be based on the weight fraction of the atoms in the molecule which came from a renewable feedstock (the “renewable atoms”), but rather must be based on the energy inherent in that portion of the molecules comprised of renewable atoms. To identify the renewable atoms within the molecules that comprise the renewable fuel, we must examine the chemical process through which the renewable fuel was produced. A detailed explanation of calculations for R and several examples are given in a technical memorandum in the docket. 23 23 “Calculation of equivalence values for renewable fuels under the RFS program”, memo from David Korotney to EPA Air Docket OAR-2005-0161. In the case of ethanol, denaturants are added to preclude the ethanol's use as food. Denaturants are generally a fossil-fuel based, gasoline-like hydrocarbon in concentrations of 2-5 volume percent, with 5 percent being the most common historical level. One commenter argued that the Equivalence Value of ethanol must be specified as 0.95 for this very reason. However, as described in the NPRM, we believe that the Equivalence Value for ethanol should be specified as 1.0 despite the presence of a denaturant. First, as stated above, ethanol is expected to dominate the renewable fuel pool for at least the next several years, and it is likely that the authors of the Act recognized this fact. Thus it seems likely that it was the intent of the authors of the Act that each physical gallon of denatured ethanol be counted as one gallon for RFS compliance purposes. Second, the accounting of ethanol has historically ignored the presence of the denaturant. For instance, under Internal Revenue Service
(IRS)regulations the denaturant can be counted as ethanol by parties filing claims to the IRS for the federal excise tax credit. Also, EIA reporting requirements for ethanol producers allow them to include the denaturant in their reported volumes. The commenter arguing for the use of an Equivalence Value of 0.95 for ethanol provided no additional information to counter these arguments. Since we are requiring that denatured ethanol be assigned an Equivalence Value of 1.0, this must be reflected in the values of R <sup>Eth</sup> and EC <sup>Eth</sup> . We have calculated these values to be 93.1 percent and 77,550 Btu/gal, respectively. Details of these calculations can be found in the aforementioned technical memorandum to the docket. The final equation to be used for calculation of Equivalence Values is therefore: EV = (R / 0.931) * (EC / 77,550) Where: EV = Equivalence Value for the renewable fuel. R = Renewable content of the renewable fuel, expressed as a percent, on an energy basis, of the renewable fuel that comes from a renewable feedstock. EC = Energy content of the renewable fuel, in Btu per gallon (lower heating value). For the specific case of biogas which cannot be measured in volumetric units, we are specifying that 77,550 Btu of biogas will be considered to be the equivalent of one gallon of renewable fuel. The calculation of the Equivalence Value for a particular renewable fuel can lead to values that deviate only slightly from 1.0, and/or can have varying degrees of precision depending on the uncertainty in the value of R or EC <sup>RF</sup> . In the NPRM we proposed several simplifications to streamline the application of Equivalence Values in the context of the RFS program. These included the use of pre-specified bins, rounding, and the use of an Equivalence Value of 1.0 when the calculated value was close to 1.0. We received some comments suggesting that these three simplifications unnecessarily complicated the determination of Equivalence Values. Based on comments received, we have determined for the final rule to simplify the application of Equivalence Values by only requiring the calculated values be rounded to the first decimal place. Also, based on consideration of comments received on how such products should be counted, for renewable diesel produced by processing fats and oils through a refinery hydrotreating process, we have determined that the default Equivalence Value should be 1.7 consistent with renewable diesel produced through other processes. This approach recognizes that hydrotreating produces a product consistent with our definition of non-ester renewable diesel. Furthermore, based on comments received, the volume of the final product is expected to be comparable to the volume of the input renewable crude. Therefore, the volume of renewable crude will be used as a surrogate for the volume of the final product. With the exception of renewable diesel produced through hydroteating fats or oils which is identical to renewable diesel, none of the specific Equivalence Values proposed in the NPRM have changed as a result of this simplification. The final values are shown in the table below. Table III.B.4-1.—Equivalence Values for Some Renewable Fuels Equivalence value
(EV)Cellulosic biomass ethanol or waste-derived ethanol 24 2.5 Ethanol from corn, starches, or sugar 1.0 Biodiesel (mono alkyl ester) 1.5 Non-ester renewable diesel and hydrotreated renewable crudes 1.7 Butanol 1.3 Renewable crude-based fuels 1.0 Consistent with the NPRM, the Equivalence Value for renewable crude-based fuels is 1.0. Although some renewable crude-based fuels might warrant a higher value based on their energy content, it is also likely that some of the renewable crude does not end up as a motor vehicle fuel. Rather than requiring the refiner to document what portion of the biocrude-based renewable fuel is other than diesel or gasoline (e.g., jet fuel), we are combining the Equivalence Value of 1.0 with a requirement that the volume of the renewable crude itself count as the volume of renewable fuel produced for the purposes of determining the volume block codes that are in the RIN (discussed in further detail in Section III.D). While this approach may result in some products such as jet fuel being counted as renewable fuel, we believe the majority of the products produced will be motor vehicle fuel because we assume refiners who elect to use biocrudes would do so to help meet the requirements of this rule. Furthermore, both diesel and gasoline presently make up about 85 percent of the product slate of refineries on average. This amount that has been steadily increasing for over time, and we expect that the percentage will continue to increase as demand for gasoline and diesel increases. Thus the designation of an Equivalence Value of 1.0 balances out the potentially higher energy content of renewable crude-based fuels with the potential for lower yields of renewable fuel produced as motor vehicle fuel. We received no comment on this issue and are finalizing it as proposed. 24 The 2.5 value is specified by the Energy Act, and is not based on the EV formula discussed earlier. Since there are a wide variety of possible renewable fuels that could qualify under the RFS program, there may be cases in which a party produces a renewable fuel not shown in Table III.B.4-1. A party may also produce a renewable fuel listed in the above table, but which has a different renewable content or energy content than the values assumed for our calculations. For such cases we have created a regulatory mechanism through which the producer may submit a petition to the Agency describing the renewable fuel, its feedstock and production process, and the calculation of its Equivalence Value. The Agency will review the petition and approve an appropriate Equivalence Value based on the information provided. We will publish newly assigned Equivalence Values in the **Federal Register** at the same time as the annual standard is published each November. In the NPRM, we also described an additional approach to setting the Equivalence Value for biodiesel (mono alkyl esters). Since ethanol derived from waste products such as animal wastes and municipal solid waste will be assigned an Equivalence Value of 2.5 based on a requirement in the Act, we pointed out that it might be appropriate to create a parallel provision for biodiesel made from wastes. Under this approach, biodiesel made from waste products would have been assigned an Equivalence Value of 2.5 through 2012. Supporters of 2.5 Equivalence Value argued that it would place the treatment of waste-derived biodiesel on the same level as waste-derived ethanol, and that it would be good Agency policy to encourage and reward parties that turn materials that would otherwise be wasted into usable motor vehicle fuel. While some of these arguments may have merit, we nevertheless believe that it is most appropriate to maintain the general methodology applicable to renewable fuels at this time and reserve the 2.5:1 valuation for just the fuel specified by Congress. Therefore, we have not finalized a 2.5 Equivalence Value for waste-derived biodiesel. For the specific case of ETBE, we have chosen for this final rule to eliminate a uniquely determined Equivalence Value. As described in Section III.D.2.b, ETBE is generally made from ethanol to which RINs will have already been assigned. An ETBE producer, therefore, would need only assign the RINs received with the ethanol to the ETBE made from that ethanol. In this case, there will be no need to generate new RINs, and therefore no need for a separate Equivalence Value. Except for cellulosic biomass ethanol and waste-derived ethanol, the Equivalence Values shown in Table III.B.4-1, or any others approved through the petition process, will be applicable for all years. However, beginning in 2013, the 2.5 to 1 ratio no longer applies for cellulosic biomass ethanol. The Act is unclear about whether the 2.5 to 1 ratio for waste-derived ethanol will apply after 2012, though it might be appropriate to treat cellulosic biomass ethanol and waste-derived ethanol in a consistent manner. Nevertheless, in the subsequent rulemaking mentioned above, we will address this issue explicitly. In today's final rule we are only specifying the ratio for cellulosic biomass and waste-derived ethanol prior to 2013. c. Lifecycle Analyses as the Basis for Equivalence Values In the NPRM we also described an alternative approach in which Equivalence Values for renewable fuels would be based on lifecycle analyses. We described both the merits and challenges associated with such an approach and requested comment. Based on the comments received we continue to believe that lifecycle analyses could provide a means of reflecting the relative benefits of one renewable fuel in comparison to another. However, we are not, in this action, establishing Equivalence Values on a lifecycle basis. Rather, we intend to continue evaluating and updating the tools and assumptions associated with lifecycle analyses in a collaborative effort with stakeholders. This rulemaking makes no determination and should not be interpreted to make any determination regarding whether EPA has the legal authority under section 1501 of the Energy Act, as incorporated in section 211(o) of the Clean Air Act, to use lifecycle analysis in establishing Equivalence Values in general or Equivalence Values specifically related to greenhouse gas or carbon dioxide emissions. This section describes some of the comments we received on the use of lifecycle analyses and our responses. Lifecycle analyses involve an examination of fossil fuel used, and emissions generated, at all stages of a renewable fuel's life. A typical lifecycle analysis examines production of the feedstock, its transport to a conversion facility, the conversion of the feedstock into renewable motor vehicle fuel, and the transport of the renewable fuel to the consumer. At each stage, every activity that consumes fossil fuels or results in emissions is quantified, and these energy consumption and emission estimates are then summed over all stages. By accounting for every activity associated with renewable fuels over their entire life, we can assess renewable fuels in terms of not just their impact within the transportation sector, but across all sectors and thus for the nation as a whole. In this way, lifecycle analyses provide a more complete picture of the potential impacts of different fuels or different fuel sources. While the use of energy content to establish Equivalence Values is an improvement over a simple gallon-for-gallon approach, a lifecycle basis would provide a further level of sophistication in assessing the net energy input and output of fuels and the emissions associated with the use of different fuels. Supporters of the use of lifecycle analyses for setting the Equivalence Values of different renewable fuels pointed to several advantages of this approach. First, doing so could create an incentive for obligated parties to choose renewable fuels having a greater ability to reduce fossil fuel use or resulting emissions, since such renewable fuels would have higher Equivalence Values and thus greater value in terms of compliance with the RFS requirements. The preferential demand for renewable fuels having higher Equivalence Values could in turn spur additional growth in production of these renewable fuels. Second, using lifecycle analyses as the basis for Equivalence Values could orient the RFS program more explicitly towards reducing petroleum use, fossil fuel use or emissions. However, the use of lifecycle analyses to establish the Equivalence Values for different renewable fuels also raises a number of issues, generally acknowledged by supporters of the use of lifecycle analyses. For instance, lifecycle analyses can be conducted using several different metrics, including total fossil fuel consumed, petroleum energy consumed, regulated pollutant emissions (e.g., VOC, NO <sup>X</sup> , PM), carbon dioxide emissions, or greenhouse gas emissions. Each metric would result in a different set of Equivalence Values. At the present time there is no consensus on which metric would be most appropriate for this purpose or the purposes of the Act. There is also no consensus on the approach to lifecycle analyses themselves. Although we have chosen to base our lifecycle analyses on Argonne National Laboratory's GREET model for the reasons described in Section IX, there are a variety of other lifecycle models and analyses available. The choice of model inputs and assumptions all have a bearing on the results of lifecycle analyses, and many of these assumptions remain the subject of debate among researchers. Lifecycle analyses must also contend with the fact that the inputs and assumptions generally represent industry-wide averages even though energy consumed and emissions generated vary widely from one facility or process to another. There currently exists no organized, comprehensive dialogue among stakeholders about the appropriate tools and assumptions behind any lifecycle analyses. We will be initiating more comprehensive discussions about lifecycle analyses with stakeholders in the near future. Another issue related to using lifecycle analyses as the basis for Equivalence Values pertains to the ultimate impact that the RFS program would have on petroleum use, fossil fuel use, regulated pollutant emissions, and/or emissions of GHGs. With a fixed volume of renewable fuel required under the RFS program, any renewable fuel with an Equivalence Value greater than 1.0 would necessarily mean that fewer actual gallons would be needed to meet the RFS standard. Thus, the advantage per gallon may be offset with fewer overall gallons, resulting in no overall additional benefit under the chosen metric for using fuels with higher Equivalence Values unless the RFS standard was simultaneously adjusted by Congress. Based on comments received in response to our NPRM, we continue to believe that the current state of scientific inquiry surrounding lifecycle analyses is not sufficiently robust to warrant its use to set Equivalence Values in this final rule. Since renewable fuel use is expected to far exceed the standards being finalized today, a higher equivalence value for those renewables with greater lifecycle benefits will likely do little to stimulate their use. However, if in the future the RFS standard more closely matches renewable demand, this could be important. We are committed to continuing our investigations into lifecycle analyses. C. What Gasoline Is Used To Calculate the Renewable Fuel Obligation and Who Is Required To Meet the Obligation? 1. What Gasoline Is Used To Calculate the Volume of Renewable Fuel Required To Meet a Party's Obligation? The Act requires EPA to promulgate regulations designed to ensure that “gasoline sold or introduced into commerce in the United States (except in noncontiguous states or territories)” contains on an annual average basis, the applicable aggregate volumes of renewable fuels as prescribed in the Act. 25 To implement this provision, today's final rule provides that the volume of gasoline used to determined the renewable fuel obligation must include all finished gasoline (RFG and conventional) produced or imported for use in the contiguous United States during the annual averaging period and all unfinished gasoline that becomes finished gasoline upon the addition of oxygenate blended downstream from the refinery or importer. This would include both unfinished reformulated gasoline, called “reformulated gasoline blendstock for oxygenate blending,” or “RBOB,” and unfinished conventional gasoline designed for downstream oxygenate blending (e.g. sub-octane conventional gasoline), called “CBOB.” The volume of any other unfinished gasoline or blendstock, such as butane, is not included in the volume used to determine the renewable fuel obligation, except where the blendstock is combined with other blendstock or finished gasoline to produce finished gasoline, RBOB, or CBOB. Where a blendstock is blended with other blendstock to produce finished gasoline, RBOB, or CBOB, the total volume of the gasoline blend is included in the volume used to determine the renewable fuels obligation for the blender. Where a blendstock is added to finished gasoline, only the volume of the blendstock is included, since the finished gasoline would have been included in the compliance determinations of the refiner or importer of the gasoline. 25 CAA Section 211(o)(2)(A)(i), as added by Section 1501(a) of the Energy Policy Act of 2005. Gasoline produced or imported for use in a noncontiguous state or U.S. territory 26 is not included in the volume used to determine the renewable fuel obligation (unless the noncontiguous state or territory has opted-in to the RFS program), nor is gasoline, RBOB or CBOB exported for use outside the United States. 26 The noncontiguous states are Alaska and Hawaii. The territories are the Commonwealth of Puerto Rico, the U.S. Virgin Islands, Guam, American Samoa, and the Commonwealth of the Northern Marianas. For purposes of this preamble, the various gasoline products (as described above) that are included in the volume of gasoline used to determine the renewable fuel obligation are collectively called “gasoline.” The final rule excludes the volume of renewable fuels contained in gasoline from the volume of gasoline used to determine the renewable fuels obligation. In implementing the Act's renewable fuels requirement, our primary goal was to design a program that is simple, flexible and enforceable. If the program were to include renewable fuels in the volume of gasoline used to determine the renewable fuel obligation, then every blender that blends ethanol downstream from the refinery or importer would be subject to the renewable fuel obligation for the volume of ethanol that they blend. There are currently approximately 1,200 such ethanol blenders. Of these blenders, only those who blend ethanol into RBOB are regulated parties under current fuels regulations. Designating all of these ethanol blenders as obligated parties under the RFS program would greatly expand the number of regulated parties and increase the complexity of the RFS program beyond that which is necessary to carry out the renewable fuels mandate under the Act. The Act provides that the renewable fuel obligation shall be “applicable to refiners, blenders, and importers, as appropriate.” 27 For the reasons discussed above, we believe it is appropriate to exclude downstream renewable fuel blenders from the group of parties subject to the renewable fuel obligation and to exclude renewable fuels from the volume of gasoline used to determine the renewable fuel obligation. This exclusion applies to any renewable fuels that are blended into gasoline at a refinery, contained in imported gasoline, or added at a downstream location. Thus, for example, any ethanol added to RBOB or CBOB downstream from the refinery or importer would be excluded from the volume of gasoline used to determine the obligation. Any non-renewable fuel added downstream, however, would be included in the volume of gasoline used to determine the obligation. This approach has no impact on the total volume of renewable fuels required (which is specified in the Act and must be met regardless of the approach taken here), but merely on the number of obligated parties. As discussed earlier, this volume of renewable fuel is likewise excluded from the calculation performed each year by EPA to determine the applicable percentage. 27 CAA Section 211(o)(3)(B), as added by Section 1501(a) of the Energy Policy Act of 2005. The NPRM was unclear with regard to whether obligated parties are to determine their renewable fuel obligation based on the gasoline production of all of their facilities in the aggregate, or each facility individually. As discussed above, EPA has discretion under the Energy Act to determine the renewable fuels obligation applicable to parties, “as appropriate.” We believe that allowing obligated parties to determine their obligation based on either their facilities in the aggregate or individually is appropriate, since allowing this flexibility will not affect compliance with the RFS. Although some commenters expressed concern that obligated parties with multiple facilities could gain an economic advantage over obligated parties with only a single facility if aggregate compliance is allowed, we do not believe that this will be the case given the unrestricted trading allowed under our program. We also believe that clarification in the regulations regarding the basis on which the obligation may be determined is a necessary and logical outgrowth of the proposal. As a result, the regulations have been modified in the final rule to clarify that the renewable fuels obligation may be determined based on the gasoline production of all of an obligated party's facilities in the aggregate, or each facility individually. We received comment that EPA should clarify when obligated parties must include imported gasoline that is used as “gasoline treated as blendstock”, or GTAB, in the volume of gasoline used to determine the party's renewable fuel obligation. As stated in the preamble to the proposed rule, GTAB is to be treated as a blendstock with regard to the RFS rule. Where the GTAB is blended with other blendstock (other than only renewable fuel) to produce gasoline, the total volume of the gasoline blend, including the GTAB, is included in the volume of gasoline used to determine the renewable fuel obligation. Where the GTAB is blended with finished gasoline, only the GTAB volume is included in the volume of gasoline used to determine the renewable fuel obligation (since the finished gasoline will already be included in the RFS calculations of the refiner of that gasoline). For purposes of compliance demonstrations, the RFS rule treats GTAB in a manner that is consistent with the reformulated gasoline
(RFG)and conventional gasoline
(CG)regulations. Under the RFG/CG regulations, importers who designate imported gasoline as GTAB must be registered with EPA as both an importer and a refiner. The importer submits separate compliance reports to EPA, one in its capacity as an importer, and one in its capacity as a refiner. The GTAB is blended by the importer and included in the importer's compliance calculations in its capacity as a refiner of the GTAB, and is excluded from the importer's compliance calculations in its capacity as an importer. The RFS rule treats GTAB in a similar manner; i.e., the importer includes the GTAB in the volume of gasoline used to determine the renewable fuel obligation of the importer in its capacity as a refiner of the GTAB, and excludes the GTAB in the volume of gasoline used to determine the renewable fuel obligation of the importer in its capacity as an importer. The regulations have been clarified with regard to how GTAB is used to determine the GTAB importer's renewable fuels obligation. We received comment that EPA should clarify that the terms RBOB and CBOB include “blendstocks for oxygenate blending” that are designed to comply with state fuels requirements, such as CARBOB (California), AZRBOB (Arizona), and LVBOB (Las Vegas). As discussed in Section III.C.1, all gasoline, and all unfinished gasoline that becomes finished gasoline upon the addition of oxygenate, that is produced or imported for use in the contiguous United States is included in the volume of gasoline used to determine an obligated party's renewable fuels obligation. As such, any finished gasoline, or unfinished gasoline that becomes finished gasoline upon the addition of oxygenate, that is produced or imported to comply with state fuels programs must also be included in the volume of gasoline used to determine an obligated party's renewable fuels obligation. The regulations have been clarified in this regard. 2. Who Is Required To Meet the Renewable Fuels Obligation? Under the final rule, any person who meets the definition of refiner under the fuels regulations, which includes any blender who produces gasoline by combining blendstocks or blending blendstocks into finished gasoline, is subject to the renewable fuels obligation. Any person who brings gasoline into the 48 contiguous states from a foreign country or from an area that has not opted-in to the RFS program, or brings gasoline from a foreign country or an area that has not opted-in to the RFS program into an area that has opted-in to the RFS program, is considered an importer under the RFS program and is subject to the renewable fuels obligation. As noted above, a blender who only blends renewable fuels downstream from the refinery or importer is not subject to the renewable fuel obligation. Any person that is required to meet the renewable fuels obligation is called an “obligated party.” We generally refer to all of the obligated parties as refiners and importers, since the covered blenders are all refiners under the regulations. A refiner or importer located in a noncontiguous state or U.S. territory is not subject to the renewable fuel obligation and thus is not an obligated party (unless the noncontiguous state or territory opts-in to the RFS program). A party located within the contiguous 48 states is an obligated party if it “imports” into the 48 states any gasoline produced or imported by a refiner or importer located in a noncontiguous state or territory. We received comment that EPA should clarify how the RFS rule applies to transmix processors and blenders. Transmix processors and blenders are treated like any other blenders under the RFS rule. Transmix processors are parties that separate the gasoline portion of the transmix from the transmix and either sell the gasoline portion as finished gasoline or blend it with other components to produce gasoline. Transmix processors exclude the gasoline portion of the transmix from the volume that is used to determine the party's renewable fuel obligation, since the gasoline portion of the transmix would have been included in the volume used to determine the renewable fuels obligation of the refiner or importer of the gasoline. In calculating the volume used to determine its renewable fuel obligation, the transmix processor would include any blendstocks (other than renewable fuels) that are added to the gasoline separated from the transmix. Where the transmix processor combines the gasoline portion of the transmix with purchased finished gasoline, both the gasoline portion of the transmix and the finished gasoline would be excluded, since the finished gasoline would have been included in the volume used to determine the renewable fuels obligation of the refiner or importer of the finished gasoline. Transmix blenders are parties that blend small amounts of unprocessed transmix into gasoline. Transmix blenders are not obligated parties if they only blend transmix into finished gasoline. If the transmix blender adds blendstocks to the transmix, the transmix blender would be an obligated party with regard to the volume of blendstocks added. The regulations have been clarified with regard to how the RFS rule applies to transmix processors and blenders. 3. What Exemptions Are Available Under the RFS Program? a. Small Refinery and Small Refiner Exemption The Act provides an exemption from the RFS standard for small refineries during the first five years of the program. The Act defines small refinery as “a refinery for which the average aggregate daily crude oil throughput for a calendar year (as determined by dividing the aggregate throughput for the calendar year by the number of days in the calendar year) does not exceed 75,000 barrels.” 28 Thus, any gasoline produced at a refinery that qualifies as a small refinery under this definition is not counted in determining the renewable fuel obligation of a refiner until January 1, 2011. Where a refiner complies with the renewable fuel obligation on an aggregate basis for multiple refineries, the refiner may exclude from its compliance calculations gasoline produced at any refinery that qualifies as a small refinery under the RFS program. This exemption applies to any refinery that meets the definition of small refinery stated above regardless of the size of the refining company that owns the refinery. Based on information currently available to us we expect 42 small refineries to qualify for this exemption. Beginning in 2011, small refineries will be required to meet the same renewable fuel obligation as all other refineries, unless their exemption is extended pursuant to § 80.1141(e). 28 CAA Section 211(o)(a)(9), as added by Section 1501(a) of the Energy Policy Act of 2005. In addition to small refineries as defined in the Act, we proposed to extend this relief to refiners who, during 2004:
(1)Produced gasoline at a refinery by processing crude oil through refinery processing units;
(2)employed an average of no more than 1,500 people, including all employees of the small refiner, any parent company and its subsidiary companies; and
(3)had a total average crude oil processing capability for all of the small refiner's refineries of 155,000 barrels per calendar day (bpcd). These size criteria were established in prior rulemakings and were the result of our analyses of small refiner impacts. Based on information currently available to us, we believe that there are only three gasoline refineries owned by small refiners that meet these criteria and that currently exceed the 75,000 bpcd crude oil processing capability defined by the Act. We received comments supporting the proposed extension of the small refinery exemption to small refiners, and we also received comments opposing the proposed provision. Commenters that supported the provision generally stated that they believe that a small refiner exemption is necessary as those entities (i.e., companies) that would qualify as small refiners are generally at an economic disadvantage due to their company size—whereas the Act only recognizes facilities, based on the size of each location. These commenters also stated that they have concerns with the cost and the availability of credits under this program, and believe that provisions for small refiners are necessary to help mitigate any significant adverse economic impact on these entities. Commenters that opposed the provision stated that they believe that EPA exceeded its discretionary authority, that there appears to be no basis on which the Agency can legitimately expand this statutory exemption to add small refiners, and that Congress “clearly did not intend that the exemption be broadened to also include small refiners.” One commenter also stated that it does not believe that small refiner provisions are necessary because this rule does not require costly capital investments like previous fuel regulations. As stated in the proposal, we believe that we have discretion in determining an appropriate lead-time for the start-up of this program, as well as discretion to determine the regulated refiners, blenders and importers, “as appropriate.” We continue to believe that some refiners, due to their size, generally face greater challenges compared to larger refiners. The Small Business Regulatory Enforcement Fairness Act (SBREFA) also recognizes this and requires agencies, during promulgation of new standards, to assess the potential impacts on small businesses (as defined by the Small Business Administration
(SBA)at 13 CFR 121.201). For those instances where the Agency cannot certify that a rule will not have a significant economic impact on a substantial number of small entities, we are required to convene a SBREFA Panel. A SBREFA Panel process—which generally takes at least six months to complete—entails performing outreach with entities that meet the definition of a small business to develop ways to mitigate potential adverse economic impacts on small entities, in consultation with SBA and the Office of Management and Budget (OMB). “Small refiners” have historically been recognized in EPA fuel regulations as those refiners who employ no more than 1,500 employees and have an average crude oil capacity of 155,000 bpcd. These refiners generally have greater difficulty in raising and securing capital for investing in capital improvements and in competing for engineering resources and projects. This rulemaking does not require that refiners make capital improvements, however there are still significant costs associated with meeting the standard. While we were not required to assess the impacts on small businesses under the Energy Policy Act, we are required to do so under SBREFA. Based on our own analysis and outreach with small refiners, our assessment is that this rule will not impose a significant adverse economic impact on small refiners if they are given the small refinery exemption. Further, as noted above, we believe that no more than three additional refiners that do not meet the Energy Policy Act's definition of a small refinery will qualify as small refiners for this rule. Therefore, we are finalizing the proposed provision that the small refinery exemption will be provided to qualified small refiners. This exemption does not mean that less renewable fuel will be used than is required in the Energy Policy Act; rather, it just means that small refiners will not be obligated to ensure that those volumes are attained during the period of their exemption. We also proposed to allow foreign refiners to apply for a small refinery or small refiner exemption under the RFS program. We requested comment on the provision and related aspects, and we received some comments in which commenters stated that they believe that there is no reason to extend the small refinery exemption to these refiners. One commenter even stated that it believes that such an allowance would be unlawful. We proposed this provision for consistency with prior gasoline-related fuel programs (anti-dumping, MSAT, and gasoline sulfur) which allowed foreign refiners to receive such exemptions, and we are finalizing the provision in this action. Under this provision, foreign small refiners and foreign small refineries can apply for an exemption from the RFS standards such that importers would not count the small refiner or small refinery gasoline volumes towards the importer's renewable volume obligation. The Energy Policy Act does not prohibit EPA from granting this avenue of relief to foreign entities, and EPA believes it is consistent with the spirit of international trade agreements to provide it. In the proposal we stated that applications for a small refinery exemption must be received by EPA by September 1, 2007 for the exemption to be effective in 2007 and subsequent calendar years. We proposed that the application should include documentation that the small refinery's average aggregate daily crude oil throughput for calendar year 2004 did not exceed 75,000 barrels; and that eligibility would be based on 2004 data (rather than 2005). Further, we proposed that the small refinery exemption would be effective 60 days after receipt of the application by EPA unless EPA notifies the applicant that the application was not approved or that additional documentation is required. We received comments on this provision in which commenters stated that requiring small refinery applications was inconsistent with the language set out in the Act. The commenters stated that small refineries should not be obligated parties in 2007 even if they do not submit a small refinery application by September 1, 2007. We agree with these statements, and believe that the Energy Policy Act did in fact intend to provide this exemption without the need for small refineries to submit applications. However, in order to ensure that this provision is not being misused, we believe that it is necessary for refiners to verify that their refineries meet the definition set out in the Act. Therefore, we are finalizing that the small refinery exemption will become active immediately upon the effective date of the rule. Refiners will only be required to send a letter to EPA verifying their status as a small refinery. We did not receive any comments on our proposal to base eligibility on 2004 data, nor did we receive comments on whether a multiple-year average should be used. We believe that eligibility should be based on 2004 data rather than on 2005 data, since it was the first full year prior to passage of the Energy Act. In addition, some refineries' production may have been affected by Hurricanes Katrina and Rita in 2005. We are thus finalizing our proposed approach to base eligibility on 2004 data. As discussed above, we proposed that refiners that do not qualify for a small refinery exemption under the 75,000 bpcd criteria, but nevertheless meet the criteria of a small refiner may apply for small refiner status under the RFS rule. We proposed that the applications must be received by EPA by September 1, 2007 for the exemption to be effective in 2007 and subsequent calendar years (similar to the small refinery exemption). We also proposed that small refiner status would be determined based on documentation submitted in the application which demonstrates that the refiner met the criteria for small refiner status during the calendar year 2004 and that EPA would notify a refiner of approval or disapproval of small refiner status by letter. The final rule provides that qualified small refiners receiving the small refinery exemption will also receive the exemption immediately upon the effective date of the rule. These refiners must also submit a verification letter showing that they meet the small refiner criteria. This letter will be similar to the small refiner applications required under other EPA fuel programs (and must contain all the required elements specified in the regulations at § 80.1142), except the letter will not be due prior to the program. Small refiner status verification letters for this rule that are later found to contain false or inaccurate information will be void as of the effective date of these regulations. Unlike the case for small refineries, small refiners who subsequently do not meet all of the criteria for small refiner status (i.e., cease producing gasoline by processing crude oil, employ more than 1,500 people or exceed the 155,000 bpcd crude oil capacity limit) as a result of a merger with or acquisition of or by another entity are disqualified as small refiners, except in the case of a merger between two previously approved small refiners. As in other EPA programs, where such disqualification occurs, the refiner must notify EPA in writing no later than 20 days following the disqualifying event. The Act provides that the Secretary of Energy must conduct a study for EPA to determine whether compliance with the renewable fuels requirement would impose a disproportionate economic hardship on small refineries. If the study finds that compliance with the renewable fuels requirements would impose a disproportionate economic hardship on a particular small refinery, EPA is required to extend the small refinery's exemption for a period of not less than two additional years (i.e., to 2013). The Act also provides that a refiner with a small refinery may at any time petition EPA for an extension of the exemption for the reason of disproportionate economic hardship. In accordance with these provisions of the Act, we are finalizing the provision that refiners with small refineries may petition EPA for an extension of the small refinery exemption. As provided in the Act, EPA will act on the petition not later than 90 days after the date of receipt of the petition. Today's regulations do not provide a comparable opportunity for an extension of the small refinery exemption for small refiners. Therefore, all parties temporarily exempted from the RFS program on the basis of qualifying as a small refiner, rather than a small refinery, must comply with the program beginning January 1, 2011 (unless they waive their exemption prior to this date). During the initial exemption period for small refineries and small refiners and any extended exemption periods for small refineries, the gasoline produced by exempted small refineries and refineries owned by approved small refiners will not be subject to the renewable fuel standard. We proposed that the automatic exemption to 2011 and any small refinery extended exemptions may be waived upon notification to EPA; and we are finalizing this provision. Gasoline produced at a refinery which waives its exemption will be included in the RFS program and will be included in the gasoline used to determine the refiner's renewable fuel obligation. If a refiner waives the exemption for its small refinery or its exemption as a small refiner, the refiner will be able to separate and transfer RINs like any other obligated party. If a refiner does not waive the exemption, the refiner could still separate and transfer RINs, but only for the renewable fuel that the refiner itself blends into gasoline (i.e. the refinery operates as an oxygenate blender facility). Thus, exempt small refineries and small refiners who blend ethanol can separate RINs from batches without opting in to the program in the same manner that an oxygenate blender is allowed to do. b. General Hardship Exemption In recent rulemakings, we have included a general hardship exemption for parties that are able to demonstrate severe economic hardship in complying with the standard. We proposed not to include provisions for a general hardship exemption in the RFS program. Unlike most other fuels programs, the RFS program includes inherent flexibility since compliance with the renewable fuels standard is based on a nationwide trading program, without any per gallon requirements, and without any requirement that the refiner or importer produce the renewable fuel. By purchasing RINs, obligated parties will be able to fulfill their renewable fuel obligation without having to make capital investments that may otherwise be necessary in order to blend renewable fuels into gasoline. We believe that sufficient RINs will be available and at reasonable prices, given that EIA projects that far greater renewable fuels will be used than required. Given the flexibility provided in the RIN trading program, including the provisions for deficit carry-over, and the fact that the standard is proportional to the volume of gasoline actually produced or imported, we continue to believe a general hardship exemption is not warranted. As a result, the final rule does not contain provisions for a general hardship exemption. c. Temporary Hardship Exemption Based on Unforeseen Circumstances In recent rulemakings, we have included a temporary hardship exemption based on unforeseen circumstances. We proposed not to include such an exemption in the RFS program. The need for such an exemption would primarily be based on the inability to comply with the renewable fuels standard due to a natural disaster, such as a hurricane. However, in the event of a natural disaster, we believe it is likely that the volume of gasoline produced by an obligated party would also drop, which would result in a reduction in the renewable fuel requirement. We, therefore, reasoned in the NPRM that unforeseen circumstances, such as a hurricane or other natural disaster, would not result in a party's inability to obtain sufficient RINs to comply with the applicable renewable fuels standard. We received several comments regarding the inclusion of a temporary hardship exemption based on unforeseen circumstances. One commenter believes it would be of value to have a mechanism for selectively waiving or modifying the RFS downward on a temporary basis in the event of unforeseen circumstances such as significant drought affecting potential crop production. The commenter believes that crop shortages could have an impact on a national level, or a major disaster may impact logistics of renewable fuel distribution regionally, necessitating a more rapid response from EPA than is provided in the Energy Act. Another commenter believes that a temporary hardship exemption based on unforeseen circumstances should be included in the rule since it is impossible to predict how the RFS program will impact small refiners. Another commenter believes that, given the variety of potentially challenging unforeseen events during the last several years, it is not inconceivable that man-made or natural circumstances could adversely impact the RFS program. A natural disaster in the agricultural section, for example, may make it difficult to meet the renewable fuels mandate which, in turn, could drive the price of RINs high enough to disrupt the gasoline market. The commenter believes that a mechanism built into the program from the outset would provide a more flexible and less disruptive way to address unforeseen circumstances than the more time-consuming waiver process provided in the Energy Act. Under other EPA fuels programs, compliance is based on a demonstration that the fuel meets certain component or emissions standards. Unforeseen circumstances, such as a natural disaster, may affect an individual refiner's or importer's ability to produce or import fuel that complies with the standards. As a result, we have included in other fuels programs provisions for a temporary hardship exemption from the standards in the event of an unforeseen natural disaster that affects a party's ability to produce gasoline that complies with the standards. Unlike most other fuels programs, compliance under the RFS program is based on a demonstration that a party has fulfilled its individual renewable fuels obligation on an annual basis, as compared to meeting specific gasoline content requirements. The renewable fuels obligation can be met through the use of purchased RINs, and there is a deficit carry forward provision allowing compliance to be shown over more than one year. In the event of a natural disaster, the volume of gasoline produced by an obligated party is also likely to drop, which would result in a reduction in the party's renewable fuel obligation. As a result, we believe that an individual party would be able to meet its renewable fuel obligation even in the event of a natural disaster that affects the party's refinery or blending facility. Therefore, unlike other fuels programs, we do not believe there is a need to include a temporary hardship exemption in the RFS rule to address an individual party's inability to comply with its renewable fuels obligation due to unforeseen circumstances. Most of the concerns raised by the commenters relate to problems that would have a more regional or national effect, as compared to affecting one or a few individuals. In the event that unforeseen circumstances do occur which result in a shortage of renewable fuel and available RINs, we believe that Congress provided an adequate mechanism for addressing such situations in the Energy Act. 29 The Energy Act provides that on petition by one or more States, EPA, in consultation with the Departments of Agriculture and Energy, may waive the required aggregate renewable fuels volume obligation in whole or in part upon a sufficient showing of economic or environmental harm, or inadequate supply. As a result, we believe that a renewable fuel supply problem that affects all parties can be addressed using this statutory provision. We have carefully considered the comments; however, we do not believe that the comments provide a compelling rationale for providing a temporary hardship exemption from the RFS obligation based on unusual circumstances that goes beyond the provisions that Congress included in the Energy Act. As a result, the final rule does not contain provisions for a temporary hardship exemption based on unforeseen circumstances. 29 CAA section 211(o)(7), as added by Section 1501(a) of the Energy Policy Act of 2005. 4. What Are the Opt-in and State Waiver Provisions Under the RFS Program? a. Opt-in Provisions for Noncontiguous States and Territories The Act provides that, upon the petition of a noncontiguous state or U.S. territory, EPA may apply the renewable fuels requirements to gasoline produced in or imported into that noncontiguous state or U.S. territory at the same time as, or any time after the promulgation of regulations establishing the RFS program. 30 In granting such a petition, EPA may issue or revise the RFS regulations, establish applicable volume percentages, provide for generation of credits, and take other actions as necessary to allow for the application of the RFS program in a noncontiguous state or territory. We believe that approval of the petition does not require a showing other than a request by the Governor of the State or the equivalent official of a Territory to be included in the program. 30 CAA Section 211(o)(2)(A)(ii), as added by Section 1501(a) of the Energy Policy Act of 2005. Today's final rule will implement this provision of the Act by providing a process whereby the governor of a noncontiguous state or territory may petition EPA to have the state or territory included in the RFS program. The petition must be received by EPA on or before November 1 for the noncontiguous state or territory to be included in the RFS program in the next calendar year. A noncontiguous state or territory for which a petition is received after November 1 would not be included in the RFS program in the next calendar year, but would be included in the RFS program in the subsequent year. For example, if EPA receives a petition on September 1, 2007, the noncontiguous state or territory would be included in the RFS program beginning on January 1, 2008. If EPA receives a petition on December 1, 2007, the noncontiguous state or territory would be included in the RFS program beginning January 1, 2009. We believe that requiring petitions to be received by November 1 is necessary to allow EPA time to make any adjustments in the applicable standard. The method for calculating the renewable fuels standard to reflect the addition of a state or territory that has opted into the RFS program is discussed in Section III.A. Because today's regulations make EPA approval of an opt-in petition automatic if it is signed by the appropriate authority and properly delivered to EPA, EPA does not envision providing an opportunity to comment on an opt-in request, although we will provide notice in the publication of the standard for the following year. We received several comments regarding when a noncontiguous state or territory should be able to opt-in to the RFS program. One commenter supported the approach in this final rule that EPA use the EIA Short-term Energy Outlook published each October to assist in determining the percentage standard and therefore a state can only opt-in beginning with the first full compliance period of 2008. Another commenter believed we should include a provision to allow noncontiguous states or territories to opt-in to the first compliance period which starts September 1, 2007. While we see the merits of allowing a noncontiguous state or territory to opt-in to the first compliance period, we intend to maintain the current approach and allow noncontiguous states and territories to opt-in beginning with the 2008 compliance year. The statute clearly states that the program may apply to noncontiguous states and territories (that have petitioned EPA) at any time after these regulations have been promulgated. Given the short period of time between publication of the final rule and the effective date of the program, the need for a state and regulated parties to discuss opting-in with knowledge of the final version of the rule, and the requirement for EPA to notify obligated parties with sufficient lead time to any change in the standard, EPA believes 2008 is the earliest practical date for an opt-in to be effective. In addition, EPA notes that none of the noncontiguous states or territories indicated a strong interest in opting-in for the remainder of the 2007 compliance period. Where a noncontiguous state or territory opts-in to the RFS program, producers and importers of gasoline for that state or territory will be obligated parties subject to the renewable fuel requirements. All refiners and importers who produce or import gasoline for use in a state or territory that has opted-in to the RFS program will be required to comply with the renewable fuel standard and will be able to separate RINs from batches of renewable fuels in the same manner as other obligated parties. Once a petition to opt-in to the RFS program is approved by EPA, the state or territory would remain in the RFS program and be treated as any of the 48 contiguous states. We received a comment asserting that once a state or territory opts-in, they should be required to remain in the program for at least 5 years. As stated earlier, EPA will recognize a state or territory that opts-in to the program as identical to any of the 48 states. The current regulations do not allow a state to opt-out and the only form of relief from the program is a waiver, in whole or in part, of the national renewable fuel volume requirement. Noncontiguous states and territories should be aware of the obligations of the program and should only choose to opt-in if they expect to meet those obligations for the indefinite future. If in the future a state believes EPA should change its regulations and allow an opt-out the state could petition EPA to change the regulations. As in other situations where a party petitions EPA to revise its regulations, EPA would be in a position at that point to consider the concerns raised by the state as well as other interested stakeholder and to determine whether it would be appropriate to revise the regulations. b. State Waiver Provisions The Energy Act provides that EPA, in consultation with the U.S. Department of Agriculture
(USDA)and the Department of Energy (DOE), may waive the renewable fuels requirements in whole or in part upon a petition by one or more states by reducing the national quantity of renewable fuel required under the Act. 31 The Act also outlines the basic requirements for such a waiver, such as a demonstration that implementation of the renewable fuels requirements would severely harm the economy or environment of a state, a region, or the United States or that there is an inadequate domestic supply of renewable fuel. 31 CAA Section 211(o)(7), as added by Section 1501(a) of the Energy Policy Act of 2005. If EPA, after public notice and opportunity for comment, approves a state's petition for a waiver of the RFS program, the Act stipulates that the national quantity of renewable fuel required (Table I.B-1) may be reduced in whole or in part. This reduction could reduce the percentage standard applicable to all obligated parties. However, there is no provision in the Act that would permit EPA to reduce or eliminate any obligations under the RFS program specifically for parties located within the state that petitioned for the waiver. Thus all refiners, importers, and blenders located in the state would still be obligated parties if they produce gasoline. In addition, an approval of a state's petition for a waiver may not have any impact on renewable fuel use in that state since it would not be a prohibition on the sale or consumption of renewable fuels in that state. In fact, the Act prohibits the regulations from restricting the geographic areas in which renewable fuels may be used. 32 Renewable fuel use in the state in question would thus continue to be driven by natural market forces and, perhaps if the economics of ethanol blending were less favorable than today, the nationally-applicable renewable fuel standard. 32 CAA Section 211(o)(2)(iii), as added by Section 1501(a) of the Energy Policy Act of 2005. Given that state petitions for a waiver of the RFS program appear unlikely to affect renewable fuel use in that state, we have not finalized regulations providing more specificity regarding the criteria for a waiver or the ramifications of Agency approval of such a waiver in terms of the level or applicability of the standard. However, states can still submit petitions to the Agency for a waiver of the RFS requirements under the provision in the Energy Act and such petitions will be addressed by EPA on a case-by-case basis. We received several comments objecting to the decision to not propose regulations detailing the waiver process and our rationale for not doing so. One commenter stated that nothing in the statute prevents relief from being directed toward a state which has requested the waiver by reducing the renewable fuel obligation of refiners, blenders, and importers who market gasoline in the affected state. Contrary to the commenter's assertion, the statute states that, “[t]he Administrator * * * may waive the requirements * * * by reducing the national quantity of renewable fuel required”. 33 Congress's clear intent was to limit EPA's authority to provide relief under the state waiver provision of section 211(o)(7). Relief under that provision is limited to reducing the total national volume required under the RFS program. Thus, the renewable volume obligation for regulated parties would be reduced, but the reduced obligation would still apply to all obligated refiners, blenders and importers, including those in the state that requested the waiver. This may provide some relief to the part of the country submitting the petition, but EPA is not authorized to grant other more targeted relief such as reducing the percentage for some refiners and not others or refusing to count towards compliance renewable fuel that is produced or used in certain parts of the country. It should be noted here that this approach holds true for states or territories which have opted-in to the program as well. Once a state or territory has opted-in to the program, they will be treated as identical to any other state and specific relief will not be provided to regulated parties serving these areas after the approval of a waiver. Noncontiguous states and territories should consider this in discussions with regulated parties before opting-in to the program. 33 CAA Section 211(o)(7), as added by Section 1501(a) of the Energy Policy Act of 2005. Another commenter stated that EPA should publish regulations outlining specific criteria that will be considered in reviewing a petition, so that the public would have a more meaningful opportunity to participate in the process. While EPA realizes that the criteria provided by the statute are quite general, the rationales of severe environmental or economic harm or inadequate domestic supply are sufficient for a basic framework upon which a petition can be built and evaluated. Each situation in which a waiver may be requested will be unique, and promulgating a list of more specific criteria in the abstract may be counter-productive. Communication between the petitioning state(s), EPA, DOE, USDA, and public and industry stakeholders should begin early in the process, well before a waiver request is submitted. This communication will supply these federal agencies with a knowledgeable background of the situation prompting the potential waiver request. The waiver request may even prove unnecessary after an initial investigation and analysis of the situation. If not, and if the state continues to believe that a valid basis for submission of a petition exists, federal agencies can instruct the state(s) as to what more detailed information is needed for waiver approval. Petitions will be published in the **Federal Register** , as required by statute, to provide public notice and opportunity for comment. A third commenter raised the point that there is no provision in the Act that would permit EPA to waive any obligations for specific entities in a state that has petitioned for a waiver, and in the case of an emergency, such as a natural disaster, specific relief may be warranted. The commenter is correct in the observation that EPA cannot waive obligations for specific entities or locations. However, the Act does authorize EPA to waive the obligations of the program as it applies to all obligated parties, in whole or in part, depending on the severity of the situation. D. How Do Obligated Parties Comply With the Standard? Under the Act, EPA is to establish a renewable fuel standard annually, expressed as a percentage of gasoline sold or introduced into commerce, that will ensure that overall a specified total national volume of renewable fuels will be used in gasoline in the U.S. The Act does not require each obligated party to necessarily do the blending themselves in order to comply with this obligation. Rather, under the credit trading program required by the Act, each obligated party is allowed to satisfy its obligations either through its own actions or through the transfer of credits from others who have more than satisfied their individual requirements. This section describes our final compliance program. It is based on the use of unique renewable identification numbers
(RINs)assigned to batches of renewable fuel by renewable fuel producers and importers. These RINs can then be sold or traded, and ultimately used by any obligated party to demonstrate compliance with the applicable standard. Excess RINs serve the function of the credits envisioned by the Act and also provide additional benefits, as described below. We believe that our approach is consistent with the language and intent of the Act and preserves the natural market forces and blending practices that will keep renewable fuel costs to a minimum. 1. Why Use Renewable Identification Numbers? Once renewable fuels are produced or imported, there is very high confidence that all but de minimus quantities will in fact be blended into gasoline or otherwise used as motor vehicle fuels, except for exports. Renewable fuels are not used for food, chemicals, or as feedstocks to other production processes. In fact the denaturant that must be added to ethanol is designed specifically to ensure that the ethanol is primarily used as motor vehicle fuel. In discussions with stakeholders prior to release of the NPRM, it became clear that other renewable fuels, including biodiesel and renewable fuels used in their neat (unblended) form, likewise are not used in appreciable quantities for anything other than motor vehicle fuel. Therefore if a refiner ensures that a certain volume of renewable fuel has been produced, in effect they have also ensured that this volume will be blended into gasoline or otherwise used as a motor vehicle fuel. Focusing on production of renewable fuel as a surrogate for use of such fuel has many benefits as far as streamlining the program and minimizing the influence that the program has on the operation of the market. In order to implement a program that is based on production of a certain volume of renewable fuels, we are finalizing a system of volume accounting and tracking of renewable fuels. We are requiring that this system be based on the assignment of unique numbers to each batch of renewable fuel. These numbers are called Renewable Identification Numbers or RINs, and are assigned to each batch by the renewable fuel producer or importer. The use of RINs allows the Agency to measure and track renewable fuel volumes starting at the point of their production rather than at the point when they are blended into conventional fuels. Although an alternative approach would be to measure renewable fuel volumes as they are blended into conventional gasoline or diesel, measuring renewable fuel volumes at the point of production provides more accurate measurements that can be easily verified. For instance, ethanol producers are already required to report their production volumes to EIA through Monthly Oxygenate Reports. These data provide an independent source for verifying volumes. The total number of batches and parties involved are also minimized in this approach. The total number of batches is smallest at the point of production, since batches are commonly split into smaller ones as they proceed through the distribution system to the place where they are blended into conventional fuel. The number of renewable fuel producers is also far smaller than the number of blenders. Currently there just over 100 ethanol plants and 85 biodiesel plants in the U.S., compared with approximately 1200 blenders 34 based on IRS data. 34 Those blenders who add ethanol to RBOB are already regulated under our reformulated gasoline regulations. The assignment of RINs to batches of renewable fuel at the point of their production also allows those batches to be identified according to various categories important for compliance purposes. For instance, the RIN will contain a component that specifies whether a batch of ethanol was made from cellulosic feedstocks. This RIN component will be of particular importance for 2013 and beyond when the Act specifies a national volume requirement for cellulosic biomass ethanol. The RIN will also identify the Equivalence Value of the renewable fuel which will often only be known at the point of its production. Finally, the RIN will identify the year in which the batch was produced, a critical element in determining the applicable time period within which RINs are valid for compliance purposes. Although production volumes of renewable fuels intended for blending into gasoline are a reasonably accurate surrogate for volumes ultimately blended into gasoline, changes can occur at various times throughout the year in the volumes of renewable fuel that are in storage. These stock changes involve the temporary storage of renewable fuel during times of excess and can affect the length of time between production and ultimate use. While there may be seasonal fluctuations in stocks due to seasonal demand, these stock changes always have a net change of zero over the long term since there is no economic benefit to stockpiling renewable fuels. As a result there is no need to account for stock changes in our program. Exports of renewable fuel represent the only significant distribution pathway that could impair the use of production as a surrogate for renewable fuel blending into gasoline or other use as a motor vehicle fuel. However, our approach accounts for exports through an explicit requirement placed upon exporters (discussed in Section III.D.4 below). As a result, we are confident that our approach satisfies the statutory obligation that our regulations impose obligations on refiners and importers that will ensure that gasoline sold or introduced into commerce in the U.S. each year will contain the volumes of renewable fuel specified in the Act. By tracking the amount of renewable fuel produced or imported and subtracting the amount exported, we will have an accurate accounting of the renewable fuel actually consumed as motor vehicle fuel in the U.S. Exports of renewable fuel are discussed in more detail in Section III.D.4. a. RINs Serve the Purpose of a Credit Trading Program According to the Act, we must promulgate regulations that include provisions for a credit trading program. The credit trading program allows a refiner that overcomplied with its annual RVO to generate credits representing the excess renewable fuel. The Act stipulates that those credits can then be used within the ensuing 12 month period, or transferred to another refiner that had not blended sufficient renewable fuel into its gasoline to satisfy its RVO. In this way the credit trading program permits current blending practices to continue wherein some refiners purchase a significant amount of renewable fuel for blending into their gasoline while others do little or none, thus providing a means for all refiners to economically comply with the standard. Our RIN-based program fulfills all the functions of a credit trading program and thus meets the Act's requirements. If at the end of a compliance period a party had more RINs than it needed to show compliance with its renewable volume obligation, these excess RINs would serve the function of credits and could be used or traded in the next compliance period. RINs can be transferred to another party in an identical fashion to a credit. However, our program provides additional flexibility in that it permits all RINs to be transferred between parties before they are deemed to be in excess of a party's annual RVO at the end of the year. This is because a RIN serves two functions: It is direct evidence of compliance and, after a compliance year is over, excess RINs serve the function of credits for overcompliance. Thus the RIN approach has the advantage of allowing real-time trading without having to wait until the end of the year to determine excess. As in other motor vehicle fuels credit programs, we are also requiring that any renewable producer that generates RINs must use an independent auditor to conduct annual reviews of the party's renewable production, RIN generation, and RIN transactions. These reviews are called “attest engagements,” because the auditor is asked to attest to the validity of the regulated party's credit transactions. For example, the reformulated gasoline program requires attest engagements for refiners and importers, and downstream oxygenate blenders to verify the underlying documentation forming the basis of the required reports (40 CFR part 80, subpart F). In the case of RIN generation, the auditor is required to verify that the number of RINs generated matched the volume of renewable fuels produced, that any extra value RINs are appropriately generated, and that RIN numbers are properly transferred with the renewable fuel as required by the regulations. b. Alternative Approach to Tracking Batches If we had not implemented a RIN-based system for uniquely identifying, measuring, and tracking batches of renewable fuel, the RFS program would necessarily require that we measure renewable fuel volumes at the point in the distribution system where they are actually blended into conventional gasoline or diesel or used in their neat form as motor vehicle fuel. The NPRM described a number of significant problems that this approach would create, including the potential for double-counting, increasing the number of parties subject to enforcement provisions, and the loss of a distinction between cellulosic ethanol and other forms of ethanol. We concluded that a blender-based approach to tracking volumes of renewable fuel was inferior to our proposed program focusing on the point of production and importation. We did not receive any comments supporting a blender-based approach and, consistent with the rationale provided in the proposed rule, have decided not to implement it. 2. Generating RINs and Assigning Them to Batches a. Form of Renewable Identification Numbers Each RIN is generated by the producer or importer of the renewable fuel and uniquely identifies not only a specific batch, but also every gallon in that batch. The RIN consists of a 38-character code having the following form: RIN: KYYYYCCCCFFFFFBBBBBRRDSSSSSSSSEEEEEEEE Where: K = Code distinguishing assigned RINs from separated RINs. YYYY = Calendar year of production or import. CCCC = Company ID. FFFFF = Facility ID. BBBBB = Batch number. RR = Code identifying the Equivalence Value. D = Code identifying cellulosic biomass ethanol. SSSSSSSS = Start of RIN block. EEEEEEEE = End of RIN block. In response to the NPRM, one commenter requested that the full RIN generation date, not just the year, be included in the RIN. We believe that this is unnecessary and would unduly lengthen the RIN. Compliance with the standard is determined on a calendar year basis, and the year of RIN generation is necessary in order to ensure that RINs are used for compliance purposes only in the calendar year generated or the following year. See Section III.D.3.b. The full RIN generation date, while a potentially useful piece of information in the context of potential enforcement activities, is not necessary as a component of the RIN since recordkeeping requirements contain this same information and can be consulted in the enforcement context. The company and facility IDs are assigned by the EPA as part of the registration process as described in Section IV.B. Company IDs will be used primarily to determine compliance, while the inclusion of facility IDs allows the assignment of batch numbers unique to each facility. The use of both company and facility IDs is also consistent with our approach in other fuel programs. The batch number is chosen by the producer and includes five digits to allow for facilities that produce up to a hundred thousand batches per year. In the NPRM we proposed that batch numbers be sequential values starting with 00001 at the beginning of each year. Following release of the NPRM, some stakeholders expressed the desire to be able to align RIN batch numbers with numbers used in other aspects of their business. As a result, we have determined that the requirement that the batch numbers be sequential is not necessary so long as each batch number is unique within a given calendar year. Batches are described more fully in Section III.E.1.a. The RR, D, and K codes together describe the nature of the renewable fuel and the RINs that are generated to represent it. The RR code simply represents the Equivalence Value for the renewable fuel, multiplied by 10 to eliminate the decimal place inherent in Equivalence Values. Equivalence Values form the basis for the total number of RINs that can be generated for a given volume of renewable fuel, and are described in Section III.B.4. The D code identifies cellulosic biomass ethanol batches as such. Since the Act requires that a minimum of 250 million gallons of cellulosic biomass ethanol be consumed starting in 2013, obligated parties will need to be able to distinguish RINs representing cellulosic biomass ethanol from RINs representing other types of renewable fuel. This requirement is discussed in more detail in Section III.A. In the NPRM, the K code served to distinguish between standard-value RINs and extra-value RINs, and it was placed in the middle of the RIN. As described more fully in Section III.E.1.a, our final rule eliminates the need for a distinction between standard-value RINs and extra-value RINs, but requires a distinction between RINs that must be transferred with a volume of renewable fuel (assigned RINs) and RINs that can be transferred without renewable fuel (separated RINs). Thus for the final rule we have changed the purpose of the K code. As described in Section III.E.2, we are requiring that RINs separated from volumes of renewable fuel be identified as such, by changing the K code from a value of 1 to a value of 2. Placing the K code at the beginning of the RIN makes this process more straightforward for obligated parties and oxygenate blenders who will be responsible for changing the K code after separating a RIN from renewable fuel. The RIN also contains two codes SSSSSSSS and EEEEEEEE that together identify the “RIN block” which demarcates the number of gallons of renewable fuel that the batch represents in the context of compliance. Depending on the Equivalence Value, this may not necessarily be the same as the actual number of gallons in the batch. The methodology for designating the SSSSSSSS and EEEEEEEE values is described in Section III.D.2.b below. In the NPRM we assigned six digits to the RIN block codes to allow batches up to a million gallons in size. Based on comments received, we have decided to expand the number of digits to eight to accommodate batches up to 100 million gallons in size. Although it is highly unlikely that a single tank would hold this volume, we are adding a definition of “batch” to our final regulations that would allow this high volume to be counted as a single batch for the purposes of generating RINs. In the NPRM we pointed out that “RIN” can refer to either the number representing an entire batch or the number representing one gallon of renewable fuel in the context of compliance. In order to make the distinction clear, we are defining the latter as a gallon-RIN, and a batch-RIN will represent multiple gallon-RINs. In the case of a gallon-RIN, the values of SSSSSSSS and EEEEEEEE will be identical. A batch-RIN, on the other hand, will generally have different values for SSSSSSSS and EEEEEEEE, representing the starting and ending values of a batch of renewable fuel. Examples of RINs are presented in the next section. b. Generating RINs As described in Section III.E.1.a, we have eliminated the distinction between standard-value RINs and extra-value RINs for this final rule. Instead, all gallon-RINs must be assigned to batches of renewable fuel by the producer or importer. Consistent with the NPRM, each gallon-RIN will continue to represent one gallon of renewable fuel in the context of compliance. Also consistent with the NPRM, we are requiring that RIN generation begin at the same time that the renewable fuel standard becomes applicable to obligated parties. Thus RINs must be generated for all renewable fuel produced or imported on or after September 1, 2007. Since many producers and importers will have renewable fuel in inventory at the start of the program that was produced prior to September 1, 2007, we are also allowing them to generate RINs for such renewable fuel. This provision ensures that every gallon that a producer or importer sells starting on September 1, 2007 can have an assigned RIN, and obligated parties that take ownership of renewable fuel directly from a producer or importer will have greater assurance of having access to RINs at the start of the program. Other volumes of ethanol in inventory in the distribution system on September 1, 2007 will continue to be sold and distributed without RINs. In order to determine the number of gallon-RINs that must be generated and assigned to a batch by a producer or importer, the actual volume of the batch must be multiplied by the Equivalence Value to determine an applicable “RIN volume”: V <sup>RIN</sup> = EV × V <sup>s</sup> Where: V <sup>RIN</sup> = RIN volume, in gallons, representing the number of gallon-RINs that must be generated (rounded to the nearest whole gallon). EV = Equivalence value for the renewable fuel. V <sup>s</sup> = Standardized volume of the batch of renewable fuel at 60 °F, in gallons. When RINs are first assigned to a batch of renewable fuel by its producer or importer, the RIN block start for that batch will in general be 1 (i.e., SSSSSSSS will have a value of 00000001). The RIN block end value EEEEEEEE will be equal to the RIN volume calculated above. The batch-RIN then represents all the gallon-RINs assigned to the batch. Table III.D.2.b-1 provides some examples of the number of gallon-RINs that would be assigned to a batch under different circumstances. Table III.D.2. **B** -1.—Examples of Batch-RINs 35 Batch volume: 2000 gallons corn ethanol. Equivalence value: 1.0. Gallon-RINs: 2000. Batch-RIN: 1-2007-1234-12345-00001-10-2-00000001-00002000. Batch volume: 2000 gallons biodiesel. Equivalence value: 1.5. Gallon-RINs: 3000. Batch-RIN: 1-2007-1234-12345-00002-15-2-00000001-00003000. Batch volume: 2000 gallons cellulosic ethanol. Equivalence value: 2.5. Gallon-RINs: 5000. Batch-RIN: 1-2007-1234-12345-00003-25-1-00000001-00005000. The RIN block will often represent the actual number of gallons in the batch, for cases where the Equivalence Value is 1.0. In other cases, the RIN block start and RIN block end values in the batch-RIN will not exactly correspond to the volume of the batch. For instance, in cases where the Equivalence Value is larger than 1.0, the number of gallon-RINs generated will be larger than the number of gallons in the batch. In such cases the batch will have a greater value in terms of compliance than a batch with the same volume but an Equivalence Value equal to 1.0. Likewise, a batch with an Equivalence Value less than 1.0 will have a smaller value in terms of compliance than a batch with the same volume but an Equivalence Value equal to 1.0. In the context of our modified approach to RIN distribution as described in Section III.E.1, however, the transfer of RINs with batches will be straightforward regardless of the number of gallon-RINs assigned to a particular volume of renewable fuel, as every gallon-RIN will always have the capability of covering one gallon of an obligated party's RVO. 35 RIN codes have been separated by hyphens in this table for demonstrative purposes only. In actual use, no hyphens would be present in the RIN. In response to the NPRM, some obligated parties requested that fractional RINs be used for cases in which the Equivalence Value is less than 1.0. Under this approach, every gallon in a batch would still have an assigned gallon-RIN, but those gallon-RINs would represent only a fraction of a gallon for compliance purposes. The commenters also argued that our proposed system in which RINs are assigned to only a portion of a batch would be unworkable given the need to ensure that RINs remain assigned to batches as they travel through the distribution system. We continue to believe that the most straightforward system calculates the number of gallon-RINs representing a batch as the product of the Equivalence Value and the actual volume of the batch. Then every gallon-RIN will have the capability of covering one gallon of an obligated party's RVO, and thus every gallon-RIN has the same value. This is true both for renewable fuels with Equivalence Values less than 1.0, and renewable fuels with Equivalence Values greater than 1.0. Also, as described in Section III.E.1, we have modified our approach to the distribution of RINs assigned to volumes of renewable fuel. As a result, the batch-splitting and batch-merging protocols have become largely irrelevant, and thus the transfer of renewable fuels having an Equivalence Value less than 1.0 has become greatly simplified. We are therefore finalizing our proposed approach in which renewable fuels having an Equivalence Value less than 1.0 result in fewer assigned gallon-RINs than gallons in a batch. Following release of the NPRM, we also identified some cases in which the generation of RINs for a partially renewable fuel or blending component would result in double-counting of RINs generated. For instance, ethyl tertiary butyl ether
(ETBE)is made from combining ethanol with isobutylene. The ethanol is generally from corn, and the isobutylene is generally from petroleum. The ETBE producer may purchase ethanol from another source, and that ethanol may already have RINs assigned to it. In such cases it would not be appropriate for the ETBE producer to generate additional RINs for the ETBE made from that ethanol. Even if the ETBE producer purchased ethanol without assigned RINs, our program design ensures that either RINs were generated for the ethanol and separated prior to purchase by the ETBE producer, or RINs were legitimately not assigned to the ethanol. The NPRM did not address the potential for generating RINs twice for the same renewable fuel in these cases. Therefore, we are finalizing a provision prohibiting a party from generating RINs for a partially renewable fuel or blending component that it produces if the renewable feedstock used to make the renewable fuel or blending component was acquired from another party. Any RINs acquired with the renewable feedstock (e.g. ethanol) must be assigned to the product made from that feedstock (e.g. ETBE). This approach is consistent with comments submitted by Lyondell Chemical Company. c. Cases in Which RINS Are Not Generated Although in general every batch of renewable fuel produced or imported must have an assigned batch-RIN, there are several cases in which a RIN may not be assigned to a batch by a producer or importer. For instance, if the renewable fuel was consumed within the confines of the production facility where it was made, it would not be acquired by either an obligated party or a gasoline blender. In such cases, the RIN could not be separated from the batch and transferred separately since producers do not have this right. A RIN is assigned to renewable fuel when ownership of the renewable fuel is transferred to another party. Since no such transfer would occur in this case, no RIN should be generated. A second case in which some renewable fuel would not have an assigned RIN would occur for small volume producers. We are allowing renewable fuel producers who produce less than 10,000 gallons in a year to avoid the requirement to generate RINs and assign them to batches. Such producers would not contribute meaningfully to the nationwide pool of renewable fuel, and we do not believe that the very small business operations involved should be subject to the burden of recordkeeping and reporting. Although two commenters disagreed that these small volume producers should be exempt from the requirement to generate RINs, they did not provide compelling evidence that the exemption would create a problem in the distribution system or provide an unfair advantage to small producers. As a result we are finalizing this provision as proposed. Note that if a small producer chooses to register as a renewable fuel producer under the RFS program, they will be subject to all the regulatory provisions that apply to all producers, including the requirement to assign RINs to batches. In the NPRM we proposed that a renewable fuel producer which also operated as an exporter would not be required to generate and assign a RIN to any renewable fuel that it produced and exported. However, one commenter pointed out that this approach could lead to confusion regarding which gallons should have an assigned RIN and which should not, given the complex nature of tracking volumes of renewable fuel. As a result we have determined that this provision should be eliminated. Our final regulations require that producers assign RINs to all renewable fuel, regardless of whether it is exported. Exports of renewable fuel are discussed further in Section III.D.4. 3. Calculating and Reporting Compliance Under our program, RINs form the basis of the volume accounting and tracking system that allows each obligated party to demonstrate that they have met their renewable fuel obligation each year. This section describes how the compliance process using RINs works. Our approach to the distribution and trading of RINs is covered separately in Section III.E below. a. Using RINs To Meet the Standard Under our program, each obligated party must determine its Renewable Volume Obligation
(RVO)based on the applicable percentage standard and its annual gasoline volume as described in Section III.A.4. The RVO represents the volume of renewable fuel that the obligated party must ensure is used in the U.S. in a given calendar year. Since the nationwide renewable fuel volumes shown in Table I.B-1 are required by the Act to be consumed in whole calendar years, each obligated party must likewise calculate its RVO on an annual basis. Since our program uses RINs as a measure of the amount of renewable fuel used as motor vehicle fuel that is sold or introduced into commerce within the U.S., obligated parties must meet their RVO through the accumulation of RINs. In so doing, they will effectively be causing the renewable fuel represented by the RINs to be consumed as motor vehicle fuel. Obligated parties are not required to physically blend the renewable fuel into gasoline or diesel fuel themselves. The accumulation of RINs is the means through which each obligated party shows compliance with its RVO and thus with the renewable fuel standard. For each calendar year, each obligated party is required to submit a report to the Agency documenting the RINs it acquired and showing that the sum of all gallon-RINs acquired is equal to or greater than its RVO. This reporting is discussed in more detail in Section IV. In the context of demonstrating compliance, all gallon-RINs have the same compliance value. The Agency can then verify that the RINs used for compliance purposes are valid by simply comparing RINs reported by producers to RINs claimed by obligated parties. We can also verify simply that any given gallon-RIN was not double-counted, i.e., used by more than one obligated party for compliance purposes. In order to be able to identify the cause of any double-counting, however, additional information is needed on RIN transactions as discussed in Section IV. If an obligated party has acquired more RINs than it needs to meet its RVO, then in general it can retain the excess RINs for use in complying with its RVO in the following year or transfer the excess RINs to another party. The conditions under which this is allowed are determined by the valid life of a RIN, described in more detail in Section III.D.3.b below. If, alternatively, an obligated party has not acquired sufficient RINs to meet its RVO, then under certain conditions it can carry a deficit into the next year. Deficit carryovers are discussed in more detail in Section III.D.3.d. The regulations prohibit any party from creating or transferring invalid RINs. Invalid RINs cannot be used in demonstrating compliance regardless of the good faith belief of a party that the RINs are valid. These enforcement provisions are necessary to ensure the RFS program goals are not compromised by illegal conduct in the creation and transfer of RINs. As in other motor vehicle fuel credit programs, the regulations address the consequences if an obligated party is found to have used invalid RINs to demonstrate compliance with its RVO. In this situation, the refiner or importer that used the invalid RINs will be required to deduct any invalid RINs from its compliance calculations. The refiner or importer will be liable for violating the standard if the remaining number of valid RINs is insufficient to meet its RVO, and the obligated party may be subject to additional monetary penalties if it used invalid RINs in its compliance demonstration. See Section V of this preamble for further discussion regarding liability for use of invalid RINs. Just as for RIN generators, we are also requiring that obligated parties conduct attest engagements for the volume of gasoline they produce and the number of RINs procured to ensure compliance with their RVO. In most cases, this should amount to little more than is already required under existing EPA gasoline regulations. In the case of renewable fuel exporters, the attest engagement will verify the volume of renewable fuel exported and therefore the magnitude of their RVO. Attest engagement reports must be submitted to the party that commissioned the engagement and to EPA. See Section IV of this preamble for further discussion of the attest engagement requirements. b. Valid Life of RINs The Act requires that renewable fuel credits be valid for showing compliance for 12 months as of the date of generation. This section describes our interpretation of this provision in the context of our program wherein excess RINs fulfill the Act's requirements regarding credits. As discussed in Section III.D.1.a, we interpret the Act such that credits would represent renewable fuel volumes in excess of what an obligated party needs to meet their annual compliance obligation. Given that the renewable fuel standard is an annual standard, obligated parties will determine compliance shortly after the end of the year, and credits would be identified at that time. Obligated parties will typically demonstrate compliance by submitting a compliance demonstration to EPA. Given the 12-month life of a credit as stated in the Act, we interpret this provision as meaning that credits would only be valid for compliance purposes for the following compliance year. Hence if a refiner or importer overcomplied with their 2007 obligation they would generate credits that could be used to show compliance with the 2008 compliance obligation, but the credits could not be used to show compliance for later years. Since RINs fulfill the role of credits, the statutory provisions regarding credits apply to RINs The Act's limit on credit life helps balance the risks between the needs of renewable fuel producers and obligated parties. Producers are currently making investments in expanded production capacity on the expectation of a statutorily guaranteed minimum quantity demanded. Under the market conditions we are experiencing today that make ethanol use more economically attractive, the annual volume requirements in the RFS program will not drive consumption of renewable fuels. However, if the price of crude oil dropped significantly or the use of ethanol in gasoline became otherwise less economically attractive, obligated parties could use stockpiled credits to comply with the program requirements. As a result, demand for renewable fuel could fall well below the RFS program requirements, and many producers could end up with a stranded investment. The 12 month valid life limit for credits minimizes the potential for this type of result. For obligated parties, the Act's 12 month valid life for credits provides a window within which parties who do not meet their renewable fuel obligation through their own physical use of renewable fuel can obtain credits from other parties who have excess. This critical aspect of the trading system allows the renewable fuels market to continue operating according to natural market forces, avoiding the possibility that every single refiner would need to purchase renewable fuel for blending into its own gasoline. But the 12 month life also provides a window within which banking and trading can be used to offset the negative effects of fluctuations in either supply of or demand for renewable fuels. For instance, if crude oil prices were to drop significantly and natural market demand for ethanol likewise fell, the RFS program would normally bring demand back up to the minimum required volumes shown in Table I.B-1. But in this circumstance, the use of ethanol in gasoline would be less economically attractive, since demand for ethanol would not be following price but rather the statutorily required minimum volumes. As a result, the price of credits as represented by RINs, and thus ethanol blends, could rise above the levels that would exist if no minimum required volumes existed. The 12 month valid life creates some flexibility in the market to help mitigate price fluctuations. The renewable fuels market could also experience a significant drop in supply if, for instance, a drought were to limit the production of the feedstocks needed to produce renewable fuel. Obligated parties could use banked credits to comply rather than carry a deficit into the next year. In the context of our RIN-based program, we have been able to accomplish the same objective as the Act's 12 month life of credits by allowing RINs to be used to show compliance for the year in which the renewable fuel was produced and its associated RIN first generated or for the following year. RINs not used for compliance purposes in the year in which they were generated will by definition be in excess of the RINs an obligated party needed in that year, making excess RINs equivalent to the credits referred to in the Energy Act. Excess RINs are valid for compliance purposes in the year following the one in which they initially came into existence. 36 RINs not used within their valid life will expire. This approach satisfies the Act's 12 month duration for credits. 36 The use of previous-year RINs for current year compliance purposes will also be limited by the 20 percent RIN rollover cap under today's final rule. However, as discussed in the next section, we believe that this cap will still provide a significant amount of flexibility to obligated parties. Thus we are requiring that every RIN be valid for the calendar-year compliance period in which it was generated or the following year. If a RIN was created in one year but was not used by an obligated party to meet its RVO for that year, the RIN can be used for compliance purposes in the next year (subject to certain provisions to address RIN rollover as discussed below). If, however, a RIN was created in one year and was not used for compliance purposes in that year or in the next year, it will expire. In response to the NPRM, this approach was supported by a number of obligated parties and their representative associations. These commenters agreed that allowing RINs to be used for the year generated or the following year was not only supported by the statutory language, but was also an element of program flexibility that would be critical for offsetting the negative effects of potential fluctuations in either supply of or demand for renewable fuels. However, in response to our NPRM, other commenters said that the Energy Act's 12-month credit life provision should be interpreted as applying retrospectively, not prospectively. Under this approach, the 12-month timeframe in the Act would be interpreted to refer to the full calendar year within which a credit was generated. Under this alternative approach no RINs could be used for compliance purposes beyond the calendar year in which they originally came into existence. As discussed below, we do not believe that this approach is appropriate. Commenters who supported the retrospective approach to the Act's 12-month credit life provision argued that the Energy Act could have been written to explicitly allow a valid life of multiple years if that had been Congress' intent. In response, the Act explicitly indicates that obligated parties may either use the credits they have generated or transfer them. For a party to be able to use credits generated, such credit use must necessarily occur in a compliance year other than the one in which the credit was generated. Thus we do not believe that a retrospective approach to the Act's 12-month credit life provision is consistent with the explicit credit provisions of the Act. In addition, we believe that an interpretation leading to a valid life of one year after the year in which the RIN was generated is most consistent with the program as a whole. In comparison to a single-year valid life for RINs, our approach provides some additional compliance flexibility to obligated parties as they make efforts to acquire sufficient RINs to meet their RVOs each year. This flexibility will have the effect of keeping fuel costs lower than they would otherwise be. In the comments we received on the NPRM, one objection to our proposed approach was that the use of RINs generated in one compliance period to satisfy obligations in a subsequent compliance period could result in less renewable fuel used in a given year than is set forth in the statute. While this is true, we believe this approach is most consistent with the Act, as described above. The Act clearly set up a credit program with a credit life, meaning Congress intended parties to use credits in some cases instead of blending renewable fuel. The Act is best read to harmonize all of its provisions. In addition, we note that other provisions of the Act may lead to less renewable fuel use in a given year than the statutorily-prescribed volumes, but Congress adopted them and intended that they could be used. For instance, the deficit carryover provision allows any obligated party to fail to meet its RVO in one year if it meets the deficit and its RVO in the next year. If several obligated parties took advantage of this provision, it could result in the nationwide total volume obligation for a particular calendar year not being met. In a similar fashion, the statutory requirement that every gallon of cellulosic biomass ethanol be treated as 2.5 gallons for the purposes of compliance means that the annually required volumes of renewable fuel could be met in part by virtual, rather than actual, volumes. Finally, the calculation of the renewable fuel standard is based on projected nationwide gasoline volumes provided by EIA (see Section III.A). If the projected gasoline volume falls short of the actual gasoline volume in a given year, the standard will fail to create the demand for the full renewable fuel volume required by the Act for that year. The Act contains no provision for correcting for underestimated gasoline volumes. Additional responses to the issues raised by commenters on RIN life can be found in the S&A document. c. Cap on RIN Use To Address Rollover As described in Section III.D.3.b above, RINs are valid for compliance purposes for the calendar year in which they are generated or the following year. We believe that this approach is most consistent with the Act's prescription that credits be valid for compliance purposes for 12 months as of the date of generation. Our approach is intended to address both the risk taken by producers expecting a guaranteed demand to cover their expanded production capacity investments and the risk taken by obligated parties who need a guaranteed supply in order to meet their regulatory obligations under this program. However, the use of previous year RINs to meet current year compliance obligations does create an opportunity for effectively circumventing the valid life limit for RINs. This can occur in situations wherein the total number of RINs generated each year for a number of years in a row exceeds the number of RINs required under the RFS program for those years. The excess RINs generated in one year could be used to show compliance in the next year, leading to the generation of new excess RINs in the next year, causing the total number of excess RINs in the market to accumulate over multiple years despite the limit on RIN life. The NPRM included examples of how this “rollover” might occur. The rollover issue would in some circumstances essentially make the applicable valid life for RINs virtually meaningless in practice. RIN rollover also undermines the ability of a limit on credit life to guarantee a market for renewable fuels. As described in Section III.D.3.b, if the natural market demand for ethanol was higher than the volumes required under the RFS program for several years in a row, as may occur in practice, obligated parties could amass RINs that, in the extreme, could be used entirely in lieu of actually demanding ethanol in some subsequent year. As described in the NPRM, we believe that the rollover issue must be addressed. The Act's provision regarding the valid life of credits is clearly intended to obtain the benefits associated with a limited credit life. Any program structure in which some RINs effectively have an infinite life, regardless of the technical life of individual RINs, does not appropriately achieve the benefits expected from the Act's provision regarding the 12-month life of credits. The authority to establish a credit program and to implement a limited life for credits includes the authority to limit actions that have the practical effect of circumventing this limited credit life. To be consistent with the Act, we believe that the rollover issue should be addressed in our regulations. However, we also believe that the limits to preclude such unhindered rollovers should not preclude all previous-year RINs from being used for current-year compliance. To accomplish this, we must restrict the number of previous-year RINs that can be used for current year compliance. To this end, we proposed a 20 percent cap on the amount of an obligated party's Renewable Volume Obligation
(RVO)that can be met using previous-year RINs. After review of the comments we received on the NPRM, we have decided to finalize this provision. Thus each obligated party will be required to use current-year RINs to meet at least 80 percent of its RVO, with a maximum of 20 percent being derived from previous-year RINs. Any previous-year RINs that an obligated party may have that are in excess of the 20 percent cap can be traded to other obligated parties that need them. If the previous-year RINs in excess of the 20 percent cap are not used by any obligated party for compliance, they will expire. The net result will be that, for the market as a whole, no more than 20 percent of a given year's renewable fuel standard can be met with RINs from the previous year. As described in the NPRM, we believe that the 20 percent cap provides the appropriate balance between, on the one hand, allowing legitimate RIN carryovers and protecting against potential supply shortfalls that could limit the availability of RINs, and on the other hand ensuring an annual demand for renewable fuels as envisioned by the Act. We believe this approach also provides the certainty all parties desire in implementing the program. The same cap will apply equally to all obligated parties, and the cap will be the same for all years, providing certainty on exactly how obligated parties must comply with their RVO going out into the future. A 20 percent cap will be readily enforceable with minimal additional program complexity, as each obligated party's annual report will simply provide separate listings of previous-year and current-year RINs to establish that the cap has not been exceeded. A 20 percent cap will have no impact on who could own RINs, their valid life, or any other regulatory provision regarding compliance. Some NPRM commenters did not perceive a problem with the RIN rollover issue and argued for no rollover cap or at least for a more flexible one. They pointed to the need for maximum flexibility in responding to fluctuations in the market, and they were primarily concerned about potential supply problems. For instance, if a drought were to reduce the availability of corn for ethanol production, there may simply not be sufficient RINs available for compliance purposes. A drought situation actually occurred in 1996, and as a result 1996 ethanol production was 21% less than it had been in 1995. In 1997, production had not yet returned to the 1995 levels. Moreover, there is no guarantee that future droughts, should they occur, would result in a reduction in ethanol production of only 21 percent. As a result, in the NPRM we requested comment on whether a higher cap, such as 30 percent, would be more appropriate. A number of refiners and refinery associations commented that 30 percent would indeed provide them with the additional flexibility they would need in the case of a significant market disruption. Some requested a cap of 40 percent or even no cap at all. These parties also expressed concern that, although the Agency has the authority to waive the required renewable fuel volumes in whole or in part in the event of inadequate domestic supply, this can occur only on petition by one or more states and then only after consultation with both the Department of Agriculture and the Department of Energy. Some obligated parties expressed concern that such a waiver would not occur in a timely fashion. The availability of excess previous-year RINs would thus provide compliance certainty in the event that the supply of current-year RINs falls below the RFS program requirements and the Agency does not waive any portion of the program requirements. In contrast to obligated parties, renewable fuel producers provided comments on the NPRM indicating that 10 percent would be more appropriate. They argued that a 10 percent cap was closer to their preferred approach to RIN life in which the Act's 12-month life of a credit is interpreted as allowing RINs to be used for compliance purposes only in the year in which they are generated. We continue to believe that a cap set at 20 percent is appropriate, and the comments submitted in response to the NPRM did not provide compelling evidence to the contrary. The level of 20 percent is consistent with past ethanol market fluctuations. As described above, the largest single-year drop in ethanol supply occurred in 1996 and resulted in 21% less ethanol being produced than in 1995. While future supply shortfalls may be larger or smaller, the circumstances of 1996 provide one example of their potential magnitude. We believe that a cap of 20 percent is a reasonable way to limit RIN rollover and provide some assurances to renewable fuel producers regarding demand for renewable fuel. A cap of 20 percent also ensures that many previous-year RINs can still be used for current year compliance, providing some flexibility in the event of market disruptions. Given the competing needs expressed by renewable fuel producers and refiners, a rollover cap of 20 percent also balances the risk taken by producers of renewable fuels expecting a guaranteed quantity demanded to cover their production capacity investments and the risk taken by obligated parties who need a guaranteed supply in order to meet their regulatory obligations under this program. We are therefore finalizing a rollover cap of 20 percent. In the NPRM we also considered an alternative approach whereby we would set the cap annually based on the actual excess renewable fuel production. We did not propose this approach, and commenters did not support it. We have determined that fixing the cap at 20 percent both provides certainty to the RIN market and ensures that some minimum level of flexibility exists for individual obligated parties even in a market without excess RINs. We also requested comment on whether the Agency should adopt a provision allowing the cap to be raised in the event that supply shortfalls overwhelmed the 20 percent cap. Under this conditional provision, the Agency would monitor standard indicators of agricultural production and renewable fuel supply to determine if sufficient volumes of renewable can be produced to meet the RFS program requirements in a given year. Prior to the end of a compliance period, if the Agency determined that a supply shortfall was imminent, it could raise the cap to permit a greater number of previous-year RINs to be used for current-year compliance. Although this approach would not change the required volumes, it could create some additional temporary flexibility. However, we did not propose this provision, and commenters did not address it. We do not believe it is necessary, and thus we have not finalized it. Finally, the cap is designed to prevent the rollover of RINs generated two years ago from being used for compliance purposes in the current year. No RINs were generated in 2006 when the default standard of 2.78 percent was in effect on a collective basis, so the first year in which RINs will be generated is 2007. Consequently, the first year in which there could be rollover would be 2009. Therefore, we proposed that the cap would not be effective until compliance year 2009. Two commenters pointed out that this approach could under some scenarios lead to a situation in which more than 20 percent of the RINs used for compliance purposes in 2008 were actually generated in the previous year, 2007. EPA believes that implementing the rollover cap in 2008 would, indeed, prevent the initiation of an excess buildup of past RINs. In addition, it would simplify the regulations, since there would be no need for an exception from the RIN cap for 2008. Consequently we are finalizing the 20 percent cap to apply to all years, including 2008. d. Deficit Carryovers The Energy Act also contains a provision allowing an obligated party to carry a deficit forward from one year into the next if it cannot comply with its RVO. However, deficits cannot be carried over two years in a row. Deficit carryovers are measured in gallons of renewable fuel, just as for RINs and RVOs. If an obligated party does not acquire sufficient RINs to meet its RVO in a given year, the deficit is calculated by subtracting the total number of RINs an obligated party has acquired from its RVO. There are no volume penalties, discounts, or other factors included when calculating a deficit carryover. As described in Section III.D.1, the deficit is then added to the RVO for the next year. The calculation of the RVO as described in Section III.A.4 shows how a deficit would be carried over into the next year: RVO <sup>i</sup> = (Std <sup>i</sup> × GV <sup>i</sup> ) + D <sup>i-1</sup> Where: RVO <sup>i</sup> = The Renewable Volume Obligation for the obligated party for year i, in gallons. Std <sup>i</sup> = The RFS program standard for year i, in percent. GV <sup>i</sup> = The non-renewable gasoline volume produced by an obligated party in year i, in gallons. D <sup>i-1</sup> = Renewable fuel deficit carryover from the previous year, in gallons. If an obligated party does not acquire sufficient RINs to meet its RVO in year i-1, the obligated party must procure sufficient RINs to cover the full RVO for year i including the deficit. There are no provisions allowing for another year of carryover. If the obligated party does not acquire sufficient RINs to meet its RVO for that year plus the deficit carryover from the previous year, it will be in noncompliance. The Act indicates that deficit carryovers are to occur due to “inability” to generate or purchase sufficient credits. We believe that obligated parties will make a determined effort to satisfy their RVO on an annual basis and that a deficit will demonstrate that they were unable to do so. Thus, we did not propose that any particular demonstration of “inability” be a prerequisite to the ability of obligated parties to carry deficits forward. However, one commenter requested that we should establish some sort of standard or threshold that obligated parties must meet before they would be allowed to use the deficit carryover provision. Although the commenter provided no suggestions regarding how such a threshold could be established, he indicated that in the absence of such a threshold obligated parties could potentially use the deficit carryover provision to undermine the amount of actual renewable fuel used in a given year. We agree that the deficit carryover provision could result in less renewable fuel being consumed in a given year than is required by the Act, especially if several obligated parties took advantage of it at the same time. However, in any given year some parties may be making up deficits from a prior year, while other parties might be generating deficits. This fact will tend to reduce the net effect in any given year, and regardless, the deficit in demand in one year will by regulatory requirement be made up in the following year. Finally, any threshold we could set to demonstrate an obligated party's inability to generate or purchase sufficient credits would likely require a comprehensive investigation of their opportunities to acquire RINs. Such investigations would consume Agency resources that would be better spent, in terms of ensuring that the goals of the Act are met, on other compliance enforcement matters. Therefore, we have not set any thresholds in the final rule. 4. Provisions for Exporters of Renewable Fuel As described in Section III.D.2.a, we believe that U.S. consumption of renewable fuel as motor vehicle fuel can be measured with considerable accuracy through the tracking of renewable fuel production and importing records. This is the basis for our RIN-based system of compliance. However, exports of renewable fuel must be accounted for under this approach. For instance, if a gallon of ethanol is produced in the U.S. but consumed outside of the U.S., the RIN associated with that gallon is not valid for RFS compliance purposes since the RFS program is intended to require a specific volume of renewable fuel to be consumed in the U.S. Exports of renewable fuel currently represent about 5 percent of U.S. production, though the exact value varies each year. To ensure that renewable fuels exported from the U.S. cannot be used by an obligated party for RFS compliance purposes, the RINs associated with that exported renewable fuel must be removed from circulation. For this final rule we have concluded that it should be the exporter's responsibility to account for exported renewable fuel in our RIN-based program. We are therefore requiring that an RVO be assigned to each exporter that is equal to the annual volume of renewable fuel it exported. Just as for obligated parties, then, the exporter is required to acquire sufficient gallon-RINs to meet its RVO. If the exporter purchases renewable fuel directly from a producer, that renewable fuel will come with associated gallon-RINs which can then be applied to its RVO under our program. In this circumstance, the exporter will not need to acquire RINs from any other source. If, however, the exporter receives renewable fuel without the associated RINs, it will need to acquire RINs from some other source in order to meet its RVO. In the NPRM we presented an alternative approach which would have increased the obligation placed on refiners and importers of gasoline based on the volume of renewable fuel exported. One commenter supported this alternative approach, explaining that the proposed approach of requiring the exporter to acquire sufficient RINs to offset an RVO equal to the exported volume would place a significant recordkeeping burden on exporters. This commenter also expressed concern that exporters would receive no value in return for compliance with an RVO. We do not believe that these are compelling reasons to place the burden for exported renewable fuel on obligated parties. Not only would this alternative approach have required an estimate of the volume of renewable fuel exported in the next year, but would also mean that every obligated party would share in accumulating RINs to cover the activities of other parties not under their control. In the NPRM we pointed out that in specific circumstances involving exports of renewable fuels, the need for RINs might not be necessary. For instance, if the exporter was wholly owned by a renewable fuel producer, there would be no need to generate RINs for the exported product. We therefore proposed to allow exported product to be excluded from the exporter's RVO if the exporter was also the producer and no RINs were generated for that product. However, one commenter pointed out that this approach could lead to confusion regarding which gallons should have an assigned RIN and which should not, given the complex nature of tracking volumes of renewable fuel. As a result we have determined that this provision should be eliminated. Our final regulations require producers to assign RINs to all renewable fuel, regardless of whether it is exported. In this case the renewable producer would merely use these RINs to cover its obligation as an exporter. As described in Section III.D.2, there are cases in which there is not a one-to-one correspondence between gallons in a batch of renewable fuel and the gallon-RINs generated for that batch. If the RVO assigned to the exporter were based strictly on the actual volume of the exported product, it would not necessarily capture all the gallon-RINs which were generated for that exported volume. Thus we are requiring that the RVO assigned to an exporter be based not on the actual volume of renewable fuel exported, but rather on a volume adjusted by the Equivalence Value assigned to each batch. The Equivalence Value is represented by the RR code within the RIN as described in Section III.D.2.a. Thus the exporter must multiply the actual volume of a batch by that batch's Equivalence Value to obtain the volume used to calculate the RVO. In cases wherein an exporter obtains a batch of renewable fuel whose RIN has already been separated by an obligated party or blender, the exporter may not know the Equivalence Value. We are requiring that for such cases the exporter use the equivalence value applicable to that type of renewable fuel (e.g., 1.5 for biodiesel). However, in the case of ethanol, the same product could have been produced as corn ethanol or cellulosic ethanol. Thus, in the case of ethanol, if the exporter does not know the equivalence value we are requiring that the exporter use the actual volume of the batch to calculate its RVO. This will introduce some small error into the calculation of the RVO for cases in which the ethanol had in fact been assigned an Equivalence Value of 2.5. However, we believe that the potential impact of this on the overall program will be exceedingly small. 5. How Will the Agency Verify Compliance? The primary means through which the Agency will verify an obligated party's compliance with its RVO will be the annual compliance demonstration reports. These reports will include a variety of information required for compliance and enforcement, including the demonstration of compliance with the previous calendar year's RVO, a list of all transactions involving RINs, and the tabulation of the total number of RINs owned, used for compliance, transferred, retired and expired. Reporting requirements for obligated and non-obligated parties are covered in detail in Section IV. In its annual reports, an obligated party will be required to include a list of all RINs held as of the reporting date, divided into a number of categories. For instance, a distinction must be made between current-year RINs and previous-year RINs as follows: *Current-year RINs:* RINs that came into existence during the calendar year for which the report is demonstrating compliance. *Previous-year RINs:* RINs that came into existence in the calendar year preceding the year for which the report is demonstrating compliance. The report must also indicate which RINs have been used for compliance with the RVO including any potential deficit, which current-year RINs have not been used for compliance and are therefore valid for compliance the next year, and which previous-year RINs have not been used for compliance and therefore expire. The report must also include a demonstration that the obligated party had not exceeded the 20 percent cap to address RIN rollover, as described in Section III.D.3.c. In order to verify compliance for each obligated party, the primary Agency activity will involve the validation of RINs. The Agency will perform the following four basic elements of RIN validation:
(1)RINs used by an obligated party to comply with its RVO will be checked to ensure that they are within their two-year valid life. The RIN itself will contain the year of generation, so this check involves only an examination of the listed RINs.
(2)All RINs owned by an obligated party will be cross-checked with reports from renewable fuel producers to verify that each RIN had in fact been generated.
(3)All RINs used by an obligated party for compliance purposes will be cross-checked with annual reports from other obligated parties to ensure that no two parties used the same RIN to comply.
(4)Previous-year RINs used for compliance purposes will be checked to ensure that they do not exceed 20 percent of the obligated party's RVO. In cases where a RIN is highlighted under suspicion of being invalid, the Agency will then need to take additional steps to resolve the issue. In general this will involve a review of RIN transfer records submitted quarterly to the Agency by all parties in the distribution system that held the RINs. RIN transfers will be recorded through EPA's Central Data Exchange as described in Section IV. These RIN transfer records will permit the Agency to identify all transaction(s) involving the RINs in question. The Agency can then contact liable parties and take appropriate steps to formally invalidate a RIN improperly claimed by a particular party. Additional details of the liabilities and prohibitions attributed to parties in the distribution system are discussed in Section V. E. How Are RINs Distributed and Traded? Under our final program structure, a Renewable Identification Number
(RIN)must (with certain exceptions) be generated for all renewable fuel produced or imported into the U.S., and RINs must be acquired by obligated parties for use in demonstrating compliance with the RFS requirements. However, as described in the NPRM, there are a variety of ways in which RINs could theoretically be transferred from the point of generation by renewable fuel producers to the obligated parties that need them. EPA's final program was developed in light of the somewhat unique aspects of the RFS program. As discussed earlier, under this program the refiners and importers of gasoline are the parties obligated to comply with the renewable fuel requirements. At the same time, refiners and importers do not generally produce or blend renewable fuels at their facilities and so are dependent on the actions of others for the means of compliance. Unlike EPA's other fuel programs, the actions needed for compliance largely center on the production, distribution, and use of a product by parties other than refiners and importers. In this context, we believe that the RIN transfer mechanism should focus primarily on facilitating compliance by refiners and importers and doing so in a way that imposes minimum burden on other parties and minimum disruption of current mechanisms for distribution of renewable fuels. Our final program does this by relying on the current market structure for ethanol distribution and use and avoiding the need for creation of new mechanisms for RIN distribution that are separate and apart from this current structure. Our program basically requires RINs to be transferred with renewable fuel until the point at which the renewable fuel is purchased by an obligated party or is blended into gasoline or diesel fuel by a blender. This approach allows the RIN to be incorporated into the current market structure for sale and distribution of renewable fuel, and avoids requiring refiners to develop and use wholly new market mechanisms. While the development of new market mechanisms to distribute RINs is not precluded under our program, it is also not required. In the NPRM the Agency also evaluated several options for distributing RINs other than the option incorporated into today's rule. We are not finalizing these alternatives because they tend to require the development of new market mechanisms, as compared to relying on the current market structure for distribution of ethanol, and they are less focused on facilitating compliance for the obligated parties. 1. Distribution of RINs With Volumes of Renewable Fuel We are requiring that RINs be transferred with volumes of renewable fuel as they move through the distribution system, until ownership of those volumes is assumed by an obligated party, exporter, or a party that converts the renewable fuel into motor vehicle fuel. At such time, RINs can be separated from the volumes and freely traded. This approach places certain requirements on anyone who takes ownership of renewable fuels, including renewable fuel producers, importers, marketers, distributors, blenders, and terminal operators. a. Responsibilities of Renewable Fuel Producers and Importers The initial generation of RINs and their assignment to batches of renewable fuel will be the sole responsibility of renewable fuel producers and renewable fuel importers. As described in Section III.D.1, volumes of renewable fuel can be measured most accurately and be more readily verified at these originating locations. The final rule defines a batch of renewable fuel as a volume that has been assigned a unique batch-RIN. This simple and flexible definition of a batch allows renewable fuel producers and importers to construct each batch-RIN based on the particular circumstances associated with the batch. In this context, a batch is not confined to the volume that can be held in a tank, but instead can include a significantly larger volume. However, we are placing two limits on the volumes of renewable fuel that are identified as a single batch. First, the RIN contains only enough digits to permit the assignment of 99,999,999 gallon-RINs to a single batch. For corn-ethanol with an Equivalence Value of 1.0, this means that a single batch can be comprised of up to 99,999,999 gallons of ethanol. In contrast, for biodiesel with an Equivalence Value of 1.5, a single batch can contain up to 66,666,666 gallons of biodiesel. Second, in order to provide more clarity in the event that an investigation of a party's volume and RIN generation records is conducted, we are also limiting a batch to the maximum volume that is produced or imported by the renewable fuel producer or importer within a calendar month. Within these two limits, producers and importers can define batches of renewable fuel according to their own discretion and practices, including using individual tankfulls to represent each batch. These parties must designate a unique serial number for each batch (RIN code BBBBB) and specify its Equivalence Value. The batch-RIN will identify all the gallon-RINs assigned to the batch. See Section III.D.2.a for details on the format for RINs. In the NPRM, we proposed different approaches to the assignment of standard-value RINs and extra-value RINs. Under the proposal, extra-value RINs could be generated by the renewable fuel producer in cases where the renewable fuel in question had an Equivalence Value greater than 1.0. We proposed that all standard-value RINs must be assigned to volumes of renewable fuel, but that producers should have the option of whether to assign extra-value RINs to batches. We took this approach in part out of concern that the assignment of extra-value RINs to volumes would mean that the number of gallon-RINs assigned to a batch could be greater than the number of gallons in that batch. This was of particular concern for ethanol, since a tank could contain both corn-ethanol and cellulosic ethanol. When volume was withdrawn from the tank, it would have been unclear whether the volume should be assigned the extra-value RINs or not. In the process of designing the proposed program structure to accommodate such situations, however, the program became more complicated than it needed to be. In response to the NPRM, some commenters requested that extra-value RINs be treated just like standard-value RINs. Specifically, some obligated parties, as well as gasoline marketers and distributors, argued that all RINs, be they standard-value or extra-value, should be required to travel with volumes of renewable fuel so that they will all be equally available to the obligated parties that need them for compliance. These commenters expressed concern that some producers may not release extra-value RINs, if given the choice, in an effort to drive up demand for renewable fuel. After further consideration, we have determined that in most cases there is no need to treat extra-value RINs differently from standard-value RINs in terms of whether each should be assigned to batches of renewable fuel by the producer or importer. Therefore, for most renewable fuels we are finalizing a requirement that all RINs be assigned to batches of renewable fuel by the producer or importer. Since each renewable fuel with a different Equivalence Value is a distinct fuel, producers and importers will still receive the added value of extra-value RINs that are assigned to volumes of renewable fuel if those volumes are priced appropriately in comparison to other renewable fuels with different Equivalence Values. The only exception to this is cellulosic biomass and waste-derived ethanol. Producers of such ethanol may have difficulty marketing their product at prices different than that for corn ethanol given the fungible distribution system for ethanol. The added value of the extra-value RINs may not be reflected in the price and as a result the producer may not receive any economic benefit from them. Therefore, for the case of cellulosic biomass and waste-derived ethanol we are maintaining the ability of the producer, should they so choose, to retain the extra value and not assign these RINs to the renewable fuel that they represent. In such cases, the producer of the cellulosic biomass or waste-derived ethanol would be required to change the K code from 1 to 2 in order to designate these extra RINs as separated RINs. This approach is also consistent with one of the primary motivations for the approach described in our NPRM, namely that each gallon-RIN be allowed to have a value of 1.0 to facilitate trading. Even though different renewable fuels will have different Equivalence Values and therefore different numbers of gallon-RINs per gallon, each gallon-RIN will still count as one gallon of renewable fuel for RFS compliance purposes. However, the distinction between standard-value RINs and extra-value RINs is no longer necessary. The total number of gallon-RINs that can be generated for a given batch of renewable fuel will be determined directly by its Equivalence Value as described in Section III.D.2.b, and all such gallon-RINs will be summarized in a single batch-RIN assigned to a batch. In cases where the Equivalence Value is greater than 1.0, there will be more gallon-RINs assigned to a batch of renewable fuel than gallons in that batch. Once again, in the context of the changes we are making to the RIN distribution program structure as described in Section III.E.1.b below, we do not believe that this will in any way complicate the process of distributing RINs with renewable fuel. For the specific case of cellulosic biomass or waste-derived ethanol with an Equivalence Value of 2.5, producers will be required to assign only one gallon-RIN to each gallon of ethanol, each of which has a K code value of 1. The additional 1.5 gallon-RINs that can be generated for each gallon can remain unassigned, and thus be assigned a K code value of 2. In addition to cases where the Equivalence Value is greater than 1.0, there are several other cases in which the gallon-RINs assigned to a batch will not exactly correspond to the number of gallons in that batch. First, if a renewable fuel has an Equivalence Value less than 1.0, then there will be fewer gallon-RINs than gallons in the batch. Such potential circumstances are described in Section III.D.2.c. RINs may also not correspond exactly to gallons if the density of the batch changes due to changes in temperature. For instance, under extreme changes in temperature, the volume of a batch of ethanol can change by 5 percent or more. For this reason we are requiring that all batch volumes be corrected to represent a standard condition of 60 °F prior to the assignment of a RIN. For ethanol, 37 we are requiring that the correction be done as follows: 38 37 An appropriate temperature correction for other renewable fuels must likewise be used. 38 Derived from “Fuel Ethanol Technical Information,” Archer Daniels Midland Company, v1.2, 2003. V <sup>s,e</sup> = V <sup>a,e</sup> × (−0.0006301 × T + 1.0378) Where: V <sup>s,e</sup> = Standard volume of ethanol at 60 °F, in gallons. V <sup>a,e</sup> = Actual volume of ethanol, in gallons. T = Actual temperature of the batch, in °F. Since batches of ethanol are generally sold using standard volumes rather than actual volumes, this approach to assigning RINs to batches is consistent with current practices and will maintain the one-to-one correspondence between the volume block in the batch-RIN and the standardized volume of the batch. We are requiring a similar approach for biodiesel, where the volume correction must be calculated using the following equation: 39 39 Derived from R.E. Tate et al., “The densities of three biodiesel fuels at temperatures up to 300 °C,” Fuel 85
(2006)1004-1009, Table 1 for soy methyl ester. V <sup>s,b</sup> = V <sup>a,b</sup> × (−0.0008008 × T + 1.0480) Where: V <sup>s,b</sup> = Standard volume of biodiesel at 60 °F, in gallons. V <sup>a,b</sup> = Actual volume of biodiesel, in gallons. T = Actual temperature of the batch, in °F. Consistent with the NPRM, we are requiring that RIN generation begin at the same time that the renewable fuel standard becomes applicable to obligated parties. Thus RINs must be generated for all renewable fuel produced or imported on or after September 1, 2007. Since many producers and importers will have renewable fuel in inventory at the start of the program that was produced prior to September 1, 2007, we are also allowing them to generate RINs for any renewable fuel that they own on September 1, 2007. This provision ensures that every gallon that a producer or importer sells starting on September 1, 2007 can have an assigned RIN, and obligated parties that take ownership of renewable fuel directly from a producer or importer will have greater assurance of receiving RINs at the start of the program. Since RINs are not assigned to volumes until those volumes are transferred to another party, this approach also provides producers and importers of renewable fuel the flexibility to determine which of the volumes they own on September 1, 2007 constitute production as of the start of the program. Although a RIN is generated when renewable fuel is produced or imported, we do not define the point of production. However, the RIN must be assigned to a batch no later than the point in time when ownership of the batch is transferred from the producer or importer to another party. If ownership of the batch is retained by the producer or importer after the batch leaves the originating facility, the RIN need not be transferred along with the batch on product transfer documents identifying transfer of custody. The means through which RINs are transferred with volumes of renewable fuel will in some respects be left to the discretion of the renewable fuel producer or importer. The primary requirement would be that the RIN transfer be recorded on a product transfer document (PTD). The PTD can be included in any form of standard documentation that is already associated with or used to identify title to the volume or can be a separate document as described below. In many cases an invoice could serve this purpose. As in other fuels programs, we believe the PTD requirement can be met by including the required information generated and transferred in the normal course of business. RINs are transferable in the context of the RFS program and initially must be transferred along with ownership of a volume of renewable fuel. The approach that a producer or importer takes to the transfer or sale of RINs and volumes would be at their discretion, under the condition that the RIN and volume be transferred or sold on the same day and to the same party. Based on comments received, we are also permitting the transfer of RINs to be done in a separate PTD from the PTD used to transfer ownership of the volume of renewable fuel. This will provide some additional flexibility to parties who take ownership of renewable fuel with assigned RINs, permitting IT systems managing RIN transfers to be more easily incorporated into existing business management systems. Thus a party may use two separate PTDs, one for the volume and another for the RINs. However, transfer of the RINs must occur on the same day that transfer of the volume occurred, and the two PTDs must contain sufficient information to uniquely cross-reference them. In many cases an electronic transfer will suffice if sufficient information about the transfer is recorded. In the case of such parallel PTDs, we are also requiring that the PTD transferring ownership of the volume must indicate whether RINs are being transferred and the number of gallon-RINs being transferred, though it need not list the actual RINs. As described in Section III.E.1.b below, while assigned RINs must always be transferred to another party with a volume of renewable fuel, we are allowing any party that received assigned RINs with renewable fuel to thereafter transfer anywhere from zero to 2.5 gallon-RINs with each gallon of renewable fuel. This provision provides the flexibility to transfer more assigned RINs with some volumes and less assigned RINs with other volumes depending on the business circumstances of the transaction and the number of RINs that the seller has available. However, for producers and importers of renewable fuel, this level of flexibility could contribute to short-term hoarding that was the primary concern expressed by obligated parties during development of the proposed program. Therefore we are also finalizing a provision that requires producers and importers to transfer assigned gallon-RINs with gallons such that the ratio of assigned gallon-RINs to gallons is equal to the equivalence value for the renewable fuel. Since this is not possible for exempt small volume producers, or when a producer or importer obtains renewable fuel from another party without assigned RINs, exceptions are made in these cases. We received comment that EPA should require a purchaser of imported gasoline who subsequently blends renewable fuel into the imported gasoline to transfer the RINs associated with the renewable fuel back to the importer of the gasoline. The commenter suggested that this requirement would ensure that the importer of the gasoline obtains all the RINs associated with the renewable fuel blended into that gasoline in cases where the importer has a long-term contractual agreement with the party that purchases the gasoline and adds the renewable fuel. However, we do not believe that such a provision is warranted. The RFS program places the renewable fuels obligation on parties based on ownership of the gasoline at the refiner or importer level. We believe this approach is the most effective way to implement and enforce the renewable fuels requirement. We also believe it is appropriate to allow parties who add the renewable fuel to gasoline, including blenders, to separate RINs from the renewable fuel volume and to have the right to sell those RINs to any party. Individual parties may agree that, in certain situations, it would be appropriate for the RINs to be transferred from the renewable fuels blender to the importer of the gasoline. In such cases, the parties may make contractual arrangements for the transfers. We do not believe it would be appropriate or workable for EPA to require such transfers. The NPRM did not specify whether RINs should be generated for and assigned to renewable fuel that is already contained in imported gasoline (for example, a blend of 10 percent ethanol and 90 percent gasoline). Since the renewable fuel contained in imported gasoline is part of the total volume of renewable fuel in gasoline sold or introduced into commerce in the U.S., we believe it is appropriate to treat it as any other imported renewable fuel. Thus, we believe it would be appropriate for importers to assign RINs to renewable fuel contained in imported gasoline. However, the volume of renewable fuel contained in imported gasoline is very small in comparison to the volume requirements of the RFS program. If an importer of gasoline containing renewable fuel imports less than 10,000 gallons per year of renewable fuel, then that party is not required to generate RINs. But a small volume importer that chooses to generate and assign RINs to any volume of renewable fuel in imported gasoline is required to fulfill all of the requirements that apply to renewable fuel importers under the RFS rule, in addition to all of the requirements that apply to gasoline importers as obligated parties. An importer that assigns RINs to the renewable fuel in imported gasoline may separate the RINs from the renewable fuel, since the renewable fuel has been blended into gasoline. Regardless of a small volume importer's decision to generate and assign RINs to renewable fuel contained in imported gasoline, an importer that imports any gasoline containing renewable fuel must include the gasoline portion of the imported product in the volume used to determine the importer's renewable fuel obligation (and exclude the renewable fuel portion of the batch). RINs must be assigned to imported renewable fuels that are not contained in gasoline at the time of importation, unless less than 10,000 gallons of renewable fuel are imported per year. b. Responsibilities of Parties That Buy, Sell, or Handle Renewable Fuels Volumes of renewable fuel can be transferred between many different types of parties as they make their way from the production or import facilities where they originated to the places where they are blended into conventional gasoline or diesel. Some of these parties take custody but not ownership of these volumes, storing and transmitting them on behalf of those who retain ownership. Other parties take ownership but not custody, such as a refiner who purchases ethanol and has it delivered directly to a blending facility. Thus prior to blending, each volume of renewable fuel can be owned or held by any number of parties including marketers, distributors, terminal operators, and refiners. In the NPRM, we proposed that in general all parties that assume ownership of any volume of renewable fuel would be required to transfer all RINs assigned to that volume to another party to whom ownership of the volume is being transferred. The only exceptions to the requirement that RINs be transferred with volumes would be for parties who are obligated to meet the renewable fuel standard and parties who convert the renewable fuel into motor vehicle fuel. Commenters overwhelmingly supported this approach to the distribution of RINs assigned to volumes of renewable fuel, and as a result we are adopting this approach in our final program. In this context, we are also clarifying that parties taking custody of a volume of renewable fuel but not ownership of that volume would have no responsibilities with regard to the transfer of RINs. However, in response to the NPRM, several stakeholders apprised us of certain aspects of our proposed program that would limit the intended fungibility of RINs assigned to volumes of renewable fuel. While the goal of our proposed program was to permit RINs to be interchangeable with one another and to permit one assigned RIN to be exchanged with another RIN, our proposed regulations did not sufficiently capture this level of fungibility. Instead, the proposed regulations effectively required that a specific RIN assigned to a specific gallon of renewable fuel must remain assigned to that specific gallon as it travels through the distribution system. This approach was taken in order to accommodate the legitimate existence of some volumes of renewable fuel without assigned RINs, and some assigned RINs that have no corresponding volume. These situations can occur in the distribution system for several reasons, such as the following: • RINs can be separated from renewable fuel by obligated parties or blenders, and the renewable fuel re-introduced into the distribution system. • Small volume producers are exempt from generating and assigning RINs to their product. • At the start of the program, some parties may have renewable fuel in their inventories that have not been assigned a RIN. • Batches of renewable fuels with Equivalence Values less than 1.0 will have fewer gallon-RINs than gallons. • Batch volumes can swell or shrink due to temperature changes. • Batch volumes can shrink due to evaporation, spillage, leakage, or accidents. • Volume metering imprecision. Indeed, if the program could be designed such that every gallon in the distribution system always had an assigned RIN, the complete fungibility of RINs would be straightforward. However, this is not the case. In order to make assigned RINs more fungible, we are finalizing a modified version of our proposed approach. Consistent with the NPRM, no party will be permitted to change a RIN assigned to a volume of renewable fuel into an unassigned (separated) RIN except for those parties explicitly given the right to do so (for example, obligated parties and oxygenate blenders). Also consistent with the NPRM, any party not authorized to separate an assigned RIN that takes ownership of a RIN assigned to a volume of renewable fuel cannot transfer ownership of that RIN to another party without simultaneously transferring an appropriate volume of renewable fuel. However our final regulations allow any party to transfer a volume of renewable fuel without assigned RINs, or with a different number of assigned RINs than were received with the renewable fuel, as long as the number of assigned gallon-RINs held by that party at the end of a quarter is no higher than the number of gallons it owns at the end of the quarter. This will provide parties with the flexibility to decide which RINs are transferred with which volumes, and to transfer some volumes without RINs if the party took ownership of some volumes without assigned RINs. Our final regulations require only that the number of gallon-RINs held by a party at the end of a quarter be no higher than the number of gallons held by that party, adjusted by their Equivalence Value. Aside from spillage, evaporation, or volume metering imprecision, the only way that the number of gallon-RINs that are held by a party could be higher than the number of gallons held (adjusted for their Equivalence Value) is if that party transferred some volume without RINs. In such a case the excess RINs held would be deemed to have been separated from renewable fuel, in violation of the prohibition against separating RINs. While this approach creates more flexibility for parties that hold assigned RINs, it requires three additional changes to the proposed regulations. First, we are requiring parties that hold assigned RINs to also report the volumes of renewable fuel held at the end of each quarter. While the NPRM did not propose that volumes held be reported, we believe that the additional burden on parties holding assigned RINs will be minimal. The NPRM proposed that the recordkeeping requirements include information on all renewable fuel volumes transferred, so under the proposal parties holding assigned RINs would in general already have the information available. In addition, we are not requiring that all volumes held at any time during the quarter be reported, nor are we requiring that all volumes transferred be reported. Rather, parties will be required only to report the total volume of renewable fuel and the total number of gallon-RINs held on the last day of a quarter, in addition to other information regarding RINs held and transferred. Second, our modified approach requires that we distinguish between RINs assigned to renewable fuel and RINs that have already been separated from renewable fuel, since only assigned RINs would be subject to the end-of-quarter comparison of RINs held and volumes held. We have chosen to use the K code in the RIN for this purpose, since it no longer serves the purpose of distinguishing between standard-value and extra-value RINs. The K code has also been moved to the beginning of the RIN to make its value more prominent. RINs assigned to renewable fuel must have a K code of 1. Parties who legally separate a RIN from renewable fuel must change the K code for that RIN to a value of 2. The RIN then formally becomes an unassigned RIN that can be transferred independent of renewable fuel volumes. The end-of-quarter comparisons between RINs held and volumes held apply only to RINs with a K value of 1. Third, we are requiring quarterly reporting in addition to annual reports for RINs held and transferred. In the NPRM we took comment on requiring quarterly reporting for various reasons. We received both comments supporting and opposing quarterly reporting. As discussed further in Section IV, we are requiring quarterly reporting in this final rule. Under our modified program structure, quarterly reporting will be necessary to ensure that RINs are available for obligated parties' annual compliance. Quarterly reports will provide us with the ability to monitor the activities of marketers and distributors in real time to ensure that they are transferring RINs with renewable fuel, and to address potential violations as soon as they arise. As discussed in Section III.E.1.a above, we are requiring that producers and importers of renewable fuel assign all RINs to volumes of renewable fuel, consistent with our proposed approach to standard-value RINs. As a result, downstream parties can legitimately hold more gallon-RINs than gallons if some of the renewable fuel has an Equivalence Value greater than 1.0. In the context of our modified approach to RIN distribution, this fact must be taken into account in the end-of-quarter comparison of gallon-RINs held and gallons held. Thus the following equation must be satisfied at the end of each quarter by each party that has taken ownership of any assigned RINs: Σ(RIN) <sup>D</sup> ≤ Σ(V <sup>si</sup> ×EV <sup>i</sup> ) <sup>D</sup> Where: D = Last day of a quarter (Jan-Mar, Apr-Jun, Jul-Sep, Oct-Dec). Σ(RIN) <sup>D</sup> = Sum of all assigned gallon-RINs with a K code of 1 that are owned on the last day of the quarter. (V <sup>si</sup> ) <sup>D</sup> = Volume i of renewable fuel owned on the last day of the quarter, standardized to 60 °F, in gallons. EV <sup>i</sup> = Equivalence Value representing volume i. Σ(V <sup>si</sup> ×EV <sup>i</sup> ) <sup>D</sup> = Sum of all volumes of renewable fuel owned on the last day of the quarter, multiplied by their respective equivalence values. Under our fungible distribution system, the RINs received with a volume of renewable fuel may not be the RINs originally generated to represent that particular volume. Thus the Equivalence Value for a volume of renewable fuel cannot be based on the RR code of associated RINs, but instead should be determined from the composition of the renewable fuel. If the Equivalence Value for a volume of renewable fuel cannot be determined from its composition, it should be assumed to be 1.0. However, in the specific case of ethanol the owner may not know if a volume can be categorized as cellulosic biomass ethanol or waste-derived ethanol. Thus for volumes of ethanol held at the end of a quarter, the Equivalence Value should be assumed to be 2.5 to ensure that a party can legitimately hold more RINs than gallons. The above equation ensures that the total number of gallon-RINs that can be held by a party at the end of a quarter is no greater than the number of gallon-RINs he could have received given the volume of renewable fuel that he owns. Parties that do not satisfy the above equation are deemed to be in violation of the prohibition against separating RINs from volumes. Under our modified approach to RIN distribution, it might be possible for a party who owns volumes of renewable fuel with assigned RINs to hold onto all the RINs until near the end of a quarter while selling volume without RINs. Then, in order to comply with the above equation, the party could transfer all assigned RINs with a single volume of renewable fuel prior to the last day of the quarter. This approach would amount to short-term hoarding. To prevent it, we are also placing a cap on the maximum number of gallon-RINs that can be transferred with any gallon of renewable fuel. The cap is dictated by the maximum number of gallon-RINs that a party could receive with a volume of renewable fuel, which is 2.5 in the case of cellulosic biomass ethanol or waste-derived ethanol. For a party that took ownership of these types of renewable fuel, we must allow them to transfer up to 2.5 gallon-RINs with each gallon. We are also aware that there are situations in which the volume transferred to another party might be smaller than the volume originally received. This could occur due to fuel evaporation, spillage, leakage, or volume metering imprecision, and would have the effect of raising the ratio of gallon-RINs held to gallons held. For spillage/leakage involving significant volumes, we have developed a mechanism for formally retiring the RINs associated with the lost volume. See Section IV. Smaller volume losses can be accommodated by a RIN transfer cap of 2.5, which would in general allow RINs associated with lost volume to be transferred with remaining volume. In the rare case that a party takes ownership of only cellulosic biomass ethanol or waste-derived ethanol and experiences some small volume loss, he can take ownership of a small volume of some other form of renewable fuel with an Equivalence Value less than 2.5. This will permit him to transfer RINs associated with lost volume to another party while still meeting the RIN transfer cap of 2.5. Our program is designed to allow RIN transfer and documentation to occur as part of normal business practices in the context of renewable fuel distribution. Thus the incremental costs of transferring RINs with volumes is expected to be minimal. Marketers and distributors must simply add the RIN to product transfer documents such as invoices, and record the RINs in their records of volume purchases and sales. Finally, the final rule also provides that a foreign entity may apply to EPA for approval to own RINs. As an approved foreign RIN owner, the foreign entity will be able to obtain, sell, transfer and hold both assigned and separated RINs. An approved foreign RIN owner will be required to comply with all requirements that apply to domestic RIN owners under the RFS rule. In addition, similar to other fuels programs, an approved foreign RIN owner will be required to comply with additional requirements designed to ensure that enforcement of the RFS regulations at the foreign RIN owner's place of business will not be compromised. c. Batch Splits and Batch Mergers In the RIN distribution approach proposed in the NPRM, RINs assigned to a given volume of renewable fuel remained assigned to that volume as it moved through the distribution system. In that context, batch splits and batch mergers required special treatment. We discussed the need for protocols to ensure that RINs assigned to parent batches were appropriately distributed among daughter batches, and that RINs assigned to batches that were merged were all re-assigned to the new combined batch. The proposed regulations included some restrictions on how parent batch RINs were to be apportioned to daughter batches during splits, but fell short of prescribing a detailed batch split protocol. Nevertheless, commenters by and large did not address these protocols in their comments. The need for protocols for batch splits and batch mergers was directly related to the NPRM's approach to the distribution of RINs with volumes of renewable fuel. As described in Section III.E.1.b above, we are modifying our approach to permit assigned RINs to be more fungible. As a result, there is no need for the regulations to specify any batch splitting or batch merging protocols. Under our final regulations, parties taking ownership of volumes of renewable fuel with assigned RINs will simply retain an inventory of all assigned RINs owned. As volumes of renewable fuel are then transferred to other parties, an appropriate number of gallon-RINs are withdrawn from the party's inventory and transferred along with the renewable fuel. There is no need for the party to determine which RINs were originally assigned to the volume being transferred. For parties handling both ethanol and biodiesel, it would be reasonable to transfer RINs with volumes in a manner consistent with the Equivalence Value of the renewable fuel, but this would not be required under our final regulations in which the number of assigned gallon-RINs transferred with each gallon of renewable fuel can be anywhere between zero and 2.5. In addition, volumes of renewable fuel can be split or merged any number of times while remaining under the ownership of a single party, with no impact on RINs. It is only when ownership of a volume of renewable is transferred to another party that an appropriate number of gallon-RINs need to be withdrawn from the party's inventory and assigned to the transferred volume, subject to the flexibility associated with the quarterly average as discussed above. 2. Separation of RINs From Volumes of Renewable Fuel Separation of a RIN from a volume of renewable fuel means that the RIN is no longer included on the PTD and can be traded independently from the volume to which it had originally been assigned. In general commenters supported our proposed approach of limiting the parties that can separate a RIN from a batch, and the associated conditions under which separation can occur. In designing the regulatory program, we structured it around facilitating compliance by obligated parties with their renewable fuel obligation, with the intention of giving obligated parties the power to market the renewable fuel separately from the RIN originally assigned to it. Our final program therefore requires a refiner or importer to separate the RIN from renewable fuel as soon as he assumes ownership of that renewable fuel. In the case of ethanol blended into gasoline at low concentrations (≤ 10 volume percent), stakeholders have informed us that a large volume of the ethanol is purchased by refiners directly from ethanol producers, and is then passed to blenders who carry out the blending with gasoline. Therefore, in many cases RINs assigned to renewable fuel will pass directly from the producers who generated them to the obligated parties who need them. However, significant volumes of ethanol are also blended into gasoline without first being purchased by a refiner. In some cases, the blender itself purchases the ethanol. In other cases, a downstream customer purchases the ethanol and contracts with the blender to carry out the blending. Regardless, the ethanol may never be held or owned by an obligated party before it is blended into gasoline. Thus we are also requiring a blender to separate the RIN from the renewable fuel if he takes ownership of the renewable fuel and actually blends it into gasoline (or, in the case of biodiesel, into diesel fuel). This would only apply to volumes where the RIN had not already been separated by an obligated party. Since blenders will in general not be obligated parties under our program, blenders who separate RINs from renewable fuel will have no need to hold onto those RINs and thus can transfer them to an obligated party for compliance purposes or to any other party. There may be occasions in which a retailer downstream of a blender actually owns the volume of renewable fuel when it is blended into gasoline or diesel. In such cases the blender will have custody but not ownership of the renewable fuel. In today's final rule we are requiring the RIN to be separated from the volume of renewable fuel when that volume is blended into gasoline, but the RIN can only be separated by the party that owns that volume of renewable fuel at the time of blending. In the case of a blender and a downstream customer who might both lay claim to the right to separate any assigned RINs (for instance, if transfer of ownership occurred simultaneous with blending), these two parties would need to come to agreement between themselves regarding which party will own the separated RINs. As described in Section III.B, many different types of renewable fuel can be used to meet the RFS volume obligations placed upon refineries and importers. Currently, ethanol is the most prominent renewable fuel and is most commonly used as a low level blend in gasoline at concentrations of 10 volume percent or less. However, some renewable fuels can be used in neat form (i.e. not blended with conventional gasoline or diesel). The two RIN separation situations described above would capture any renewable fuel for which ownership is assumed by an obligated party or a party that blends the renewable fuel into gasoline or diesel. However, renewable fuels which are used in their neat (unblended) form as motor vehicle fuel would not be captured. This would include such renewable fuels as neat biodiesel
(B100)or renewable diesel, methanol for use in a dedicated methanol vehicle or biogas for use in a CNG vehicle. Under our final program, producers and importers must assign a RIN to all renewable fuels produced or imported, including neat renewable fuels. To avoid the possibility that the RIN assigned to neat renewable fuel would never become available to an obligated party for RFS compliance purposes, in the NPRM we proposed to more broadly define the right to separate a RIN from renewable fuel. In addition to obligated parties and blenders, we proposed that any producer holding a volume of renewable fuel for which the RIN has not been separated could separate the RIN from that volume if the party designates it for use only as a motor vehicle fuel in its neat form and it is in fact only used as such. This approach would recognize that the neat form of the renewable fuel is valid for compliance purposes under the RFS program, as described in Section III.B. In effect, it would place neat fuel producers in the same category as blenders, in that they are producing motor vehicle fuel. We did not receive any negative comments on this proposal, and thus are finalizing this provision as proposed. As discussed above, under our final rule, obligated parties must separate RINs from volumes of renewable fuel. This applies to all volumes of renewable fuel that an obligated party owns. The requirement to separate a RIN from the renewable fuel is intended to apply to refiners, blenders and importers for whom the production or importation of gasoline is a significant part of their overall business operations. Parties that are predominately renewable fuel producers or importers, but which must be designated as obligated parties due to the production or importation of a small amount of gasoline, should not be able to separate RINs from all renewable fuels that they own. For example, we believe it would be inappropriate to permit an ethanol producer to separate RINs from all volumes that they own simply because the producer imported, for example, a single truckload of gasoline from Canada or Mexico. As a result, the final rule prohibits obligated parties from separating RINs from volumes of renewable fuel that they produce or import that are in excess of their RVO. However, obligated parties must separate any RINs from volumes of renewable fuel that they own if that volume was produced or imported by another party. As described in Section III.B.2, RINs can be generated for renewable fuels made from renewable crude which is treated as if it were a petroleum-derived crude oil or derivative, and is used as a feedstock in a traditional refinery processing unit. Whether the renewable crude is coprocessed with petroleum derivatives or is processed in a facility or unit dedicated to the renewable crude, the final product is generally a motor vehicle fuel. In such cases the refinery will have the responsibility of generating RINs for the renewable fuel produced. But since renewable crude is generally processed in a traditional refinery, the refiner will be an obligated party and can therefore immediately separate those RINs from the renewable fuel and transfer them to another party. As described in III.E.1.a above, cellulosic and waste-derived ethanol producers will also be permitted to separate the RINs associated with the extra 1.5 value of their ethanol production. Once a RIN is separated from a volume of renewable fuel, the PTD associated with that volume can no longer list the RIN. However, in the NPRM we requested comment on whether PTDs should include some notation indicating that the assigned RIN has been removed to avoid concerns about whether RINs assigned to batches have not been appropriately transferred with the batch. One refiner commented that the addition of such a note on a PTD would represent an unnecessary burden, while two commenters representing fuel distribution operations indicated that such a notation would be useful. Based on comments we received, we have determined that such notation on PTDs would not only be useful to parties receiving volumes of renewable fuel, but would also be an important element of our RIN distribution requirements under our modified approach. The requirement will ensure that parties who take ownership of renewable fuel without assigned RINs will know that RINs were originally assigned but subsequently removed. We also believe that such a requirement would be of minimal burden to parties that have separated a RIN from a volume of renewable fuel. As described in Section III.E.1.b, we have modified the RIN transfer requirements for the final rule to make RINs more fungible and to provide more flexibility to distributors while still requiring RINs to be transferred with volumes of renewable fuel. However, our modified approach requires that we distinguish between RINs assigned to renewable fuel and RINs that have already been separated from renewable fuel. Our final rule thus requires that parties who separate a RIN from renewable fuel must change the K code for that RIN to a value of 2. The RIN then becomes an unassigned RIN that can be transferred independent of renewable fuel volumes. In the NPRM we also provided a discussion of the unique circumstances regarding biodiesel (mono alkyl esters) 40 and the conditions under which we believed a RIN should be separated from a volume of such biodiesel. As described in the proposal, biodiesel is one type of renewable fuel that can under certain conditions be used in its neat form. However, in the vast majority of cases it is blended with conventional diesel fuel before use, typically in concentrations of 20 volume percent or less. This approach is taken for a variety of reasons, such as to reduce impacts on fuel economy, to mitigate cold temperature operability issues, to address concerns of some engine owners or manufacturers regarding the impacts of biodiesel on engine durability or drivability, or to reduce the cost of the resulting fuel. Biodiesel (mono alkyl esters) is also used in low concentrations as a lubricity additive and as a means for complying with the ultra-low sulfur requirements for highway diesel fuel. Biodiesel (mono alkyl esters) is occasionally used in its neat form. However, this approach is the exception rather than the rule. Consequently, in the NPRM we proposed that the RIN assigned to a volume of biodiesel could only be separated from that volume if and when the biodiesel was blended with conventional diesel. To avoid claims that very high concentrations of biodiesel count as a blended product, we also proposed that biodiesel must be blended into conventional diesel at a concentration of 80 volume percent or less before the RIN could be separated from the volume. 40 Throughout this Section III.E.2, “biodiesel” means mono alkyl esters, not non-ester renewable diesel. A number of commenters expressed concern that the 80 volume percent limit put biodiesel at odds with the RIN separation criteria applicable to other renewable fuels, including neat fuels. Upon further consideration, we have determined that the 80 volume percent limit remains a valid means for ensuring that the separation of RINs from biodiesel is consistent with its common use at low blend levels just as for ethanol, and that RINs are generally separated at the point in time when the biodiesel can be deemed to be motor vehicle fuel. However, based on comments received, we are changing the treatment of biodiesel for the final rule in two ways. First, obligated parties are required to separate RINs from volumes of biodiesel at the point when they gain ownership of the biodiesel, not when they blend biodiesel with conventional diesel fuel. This approach is consistent with our treatment of the RIN separation requirements for obligated parties for other renewable fuels. Parties that actually blend biodiesel into conventional diesel fuel at a concentration of 80 volume percent or less would continue to be required to separate the RIN from the biodiesel, as proposed. Second, we have determined that a biodiesel producer should be allowed to separate a RIN from a volume of biodiesel that it produces if it designates the volume of biodiesel specifically for use as motor vehicle fuel in its neat form, and the neat biodiesel is in fact used as motor vehicle fuel. In general this demonstration would require that the producer track the volume of biodiesel to the point of its final use. However, this approach to the treatment of neat biodiesel is consistent with how we are treating other renewable fuels used in their neat form. 3. Distribution of Separated RINs In the NPRM, we proposed that RINs become freely transferable once they are separated from a batch of renewable fuel. Each RIN could be held by any party and transferred between parties any number of times. We argued that the unique features of the RFS program warranted more open trading than in past fuel credit programs. In particular, RINs are generated by parties other than obligated parties, and many nonobligated parties will own RINs (for example, oxygenate blenders who have the right to separate RINs from volumes). While recognizing that limiting trading to and between obligated parties might help obligated parties to maintain control of those RINs being traded, such an approach could have the unintended effect of limiting the number of RINs that non-obligated parties contribute to the RIN market. The RFS program must work efficiently not only for a limited number of obligated parties, but a number of non-obligated parties as well. There was disagreement among commenters about whether an open RIN market was appropriate. Several parties supported our proposed approach, saying that unlimited trading among all interested parties would increase liquidity and transparency in the RIN market. They also argued that increasing the number of participants would facilitate the acquisition of RINs by obligated parties and promote economic efficiency. However, some commenters disagreed, arguing instead that an open market does not necessarily make the market any more fluid and free. They pointed to past credit programs in which only refiners and importers have been allowed to transfer credits, and argued that the success of those programs should compel the Agency to use those past credit program structures as the model for the RFS program. We continue to believe that there is a need to provide for more open trading in the RFS program and that this need warrants a unique approach for this rule. First, unlike other programs where credits generally represent overcompliance with an applicable standard and are thus supplemental to the means of compliance, under the RFS program RINs are the fundamental unit for compliance. There will be many more RINs in the RFS program than credits in other programs, and the trading structure must maximize the fluidity of those RINs. A wider RIN market will make it easier for obligated parties to get access to RINs. Second, obligated parties are typically not the ones producing the renewable fuels and generating the RINs, nor blending the renewable fuels into gasoline, so there is a need for trades to occur between obligated parties and non-obligated parties. If we prohibited everyone except obligated parties from holding RINs after they have been separated from a batch, non-obligated parties seeking avenues for releasing their RINs would only be able to release them to obligated parties. Having fewer avenues through which they could market their RINs, some non-obligated parties might opt not to transfer their RINs at all rather than participate in the RIN market with the attendant recordkeeping requirements. Furthermore, a potentially large number of oxygenate blenders, many of which will be small businesses, will be looking for ways to market their RINs. Allowing other parties, including brokers, to own and transfer RINs may create a more fluid and free market that would increase the venues for RINs to be acquired by the obligated parties that need them. Limiting RIN trading to and among obligated parties could make it more difficult for RINs to eventually be transferred to the obligated parties that need them. Some commenters argued that limiting the RIN trading market to and among obligated parties would make the program more enforceable, since there would be fewer parties to track and the sources of RINs would be more reliable. While this may be directionally true, we believe the RFS program will remain sufficiently enforceable under an open RIN market, and as discussed above, the greater need for market fluidity for this program warrants the change. The RIN number, along with the associated electronic reporting mechanism, will provide us the ability to verify the validity of RINs and the source of any invalid RINs. Since all RINs generated, traded, and used for compliance would be recorded electronically in an Agency database, these types of investigations should be straightforward. The number of RIN trades, and the parties between whom the RINs are being traded, will only have the effect of increasing the size of the database. Some commenters were concerned that an open RIN market could lead to price volatility and potentially higher prices as non-obligated speculators enter the market expressly to profit from the sale of RINs. According to commenters, these speculators would hold an unfair advantage over obligated parties that must purchase credits for compliance since speculators can hold onto RINs indefinitely, driving up their price. However, by expanding the number of parties that can hold RINs, we minimize the potential for any one party to exercise market power, and thus we do not believe that such activity on the part of speculators is likely to substantively affect the availability of RINs or their price. Moreover, we do not believe that a given party will hold a RIN indefinitely simply to increase profit because RINs have a limited life and new RINs will be generated and will enter the market continuously. Based on our review of the comments received, we did not find compelling evidence that an open market for RINs would create particular difficulties for obligated parties seeking RINs or would limit the enforceability of the program. As a result we are finalizing a RIN trading program that permits any party to hold RINs and for RINs to be traded any number of times. As with other credit-trading programs, the business details of RIN transactions, such as the conditions of a sale or any other transfer, RIN price, role of mediators, etc. will be at the discretion of the parties involved. The Agency is concerned only with information such as who holds a given RIN at any given moment, when transfers of RINs occur, who the party to the transfers are, and ultimately which obligated party relies on a given RIN for compliance purposes. This type of information will therefore be the subject of various recordkeeping and reporting requirements as described in Section IV, and these requirements will generally apply regardless of whether a RIN has been separated from a batch. The means through which RIN trades occur will also be at the discretion of the parties involved. For instance, parties with RINs can create open auctions, contract directly with those obligated parties who seek RINs, use brokers to identify potential transferees and negotiate terms, or just transfer the RINs to any other party. Brokers involved in RIN transfer can either operate in the role of arbitrator without owning the RINs, or alternatively can take custody of the RINs from one party and transfer them to another. If they are the transferee of any RINs, they will also be subject to the registration, recordkeeping, and reporting requirements. The Agency will not be directly involved in RIN transfers, other than in the role of providing a database within which transfers will be recorded for enforcement purposes. In order to provide public information that could be helpful in managing and trading RINs as well as understanding how the program is operating, we intend to publish a report each year that summarizes information submitted to us through the quarterly and annual reports required as part of our enforcement efforts (see Section IV). Annual summary reports published by EPA may include such information as the number of RINs generated in each month or in each state, the average number of trades that RINs undergo before being used for compliance purposes, or the frequency of deficit carryovers. However, we will not publish information identifying specific parties. 4. Alternative Approaches to RIN Distribution In the NPRM, we also described several alternative approaches to the proposed trading and compliance program that were offered by stakeholders. Most of these alternatives recognized the value of a RIN-based system of compliance, but they differed in terms of which parties would be allowed to separate a RIN from a batch and the means through which the RINs would be transferred to obligated parties. We invited comment on all of these alternatives in the NPRM, but received very few. Based on those comments we did receive, we do not believe that any of these alternative approaches should be implemented at this time. In general our responses to comments on the alternatives can be found in the Summary and Analysis of Comments document in the docket, but we have addressed one particular subject area below. In the NPRM, we described an alternative approach to RIN distribution in which obligated parties would only be able to separate a RIN from a batch of renewable fuel at the point in time when blending actually occurs. In contrast, the approach we are finalizing today requires an obligated party to separate a RIN from a batch as soon as it gains ownership of that batch. Our final program design is based on the expectation that all but a negligible quantity of renewable fuels will eventually be consumed as motor vehicle fuel, primarily through blending with gasoline or diesel. See further discussion in Section III.D. As a result, we do not believe that it is necessary to verify that blending has actually occurred in order to provide a program that adequately ensures it occurs. The American Petroleum Institute agreed that tracking renewable fuels to the point of blending would represent an unnecessary burden and added that such a requirement could preclude many obligated parties from taking direct steps to obtain RINs to meet their obligations. The Renewable Fuels Association, however, argued that allowing obligated parties to separate RINs from batches before blending occurred could give rise to RIN hoarding, fraud, and confusion. Most importantly, they noted, the alternative approach would provide direct verification of blending. For the reasons described in Section III.D, we do not believe that a compliance system requiring verification of blending is necessary, given that, with the exception of exports, essentially all renewable fuel produced in the U.S. is used as motor vehicle fuel in the U.S. This is a foundational principle of the use of a RIN-based program design that enjoyed widespread support among stakeholders and widespread recognition that it accurately describes real world practices. If verification of blending were required before a RIN could be separated from a batch, both obligated parties and blenders would be subject to additional recordkeeping and paperwork burdens. The Agency would be compelled to enforce activities at the blender level, adding about 1200 parties to the list of those subject to enforcement under our final program. Although we agree that the reformulated gasoline program could act as a model from which to construct such a recordkeeping and enforcement system, we continue to believe that such a system would be both unnecessary and burdensome. The Renewable Fuels Association also argued that our proposed program would result in confusion in the distribution system, since there would be renewable fuel both with and without RINs. However, there are many other reasons that this situation could arise, and none is expected to negatively impact the distribution of renewable fuels or the business agreements developed by parties transferring renewable fuels. For instance, we are exempting small volume producers from generating RINs, renewable fuels with equivalence values less than 1.0 may have fewer RINs than gallons, and volume swell and metering discrepancies can all contribute to situations in which batches legitimately do not have assigned RINs corresponding to their actual volumes. Parties that sell such batches could choose to price such product differently from product that has assigned RINs with a one-to-one correspondence to product volume. We are also requiring that PTDs associated with transfers of volume include notation indicating whether RINs are being simultaneously transferred to address these types of situations. Another commenter argued that the alternative approach could limit the potential for one refiner to purchase large volumes of renewable fuel with the intent of separating the RINs and exercising market power in the RIN market. However, the commenter did not provide any information regarding how such market power could be exercised by one refiner in a system where unassigned RINs can be transferred freely between parties any number of times, and access to those RINs is not limited geographically in any way. In addition, RINs that have been separated from their assigned batches by oxygenate blenders represent an additional safety valve in the RIN market, providing additional assurances that no one refiner could exercise market power in the RIN market. Commenters supporting a requirement that RINs be separated only at the point of blending offered no other arguments that hoarding or fraud could actually occur under our proposed approach. Therefore, we are finalizing an approach that requires obligated parties to separate RINs from batches at the point of ownership. IV. Registration, Recordkeeping, and Reporting Requirements A. Introduction Registration, recordkeeping and reporting are necessary to track compliance with the renewable fuels standard and transactions involving RINs. This summarizes these requirements. Our estimates as to the burden associated with registration, recordkeeping and reporting are contained in this **Federal Register** notice in Section XII.B and explained fully in “OMB-83 Supporting Statement—Renewable Fuels Standard
(RFS)Program (Final Rule)—EPA ICR No. 2242.02,” which has been placed in the public docket for this rulemaking. B. Registration 1. Who Must Register Under the RFS Program? Obligated parties (including refiners and importers), exporters of renewable fuels, producers and importers of renewable fuels, and any party who owns RINs must register with EPA. Any party may own RINs including, but not limited to, the above-named parties and marketers, blenders, terminal operators, jobbers, and brokers. Owning RINs, and engaging in any activities regarding RINs, is prohibited as of September 1, 2007 unless the party has registered and received EPA company and facility identification numbers. Most refiners and importers and many biodiesel producers are already registered with us under various regulations in 40 CFR part 80 related to reformulated
(RFG)and conventional gasoline or diesel fuel. Parties who are already registered will not have to take any action to register under the RFS program, because their existing registration will be applied to the RFS program as well. 2. How Do I Register? Registration is a simple process. We will use the same basic forms for RFS program registration that we use under the reformulated gasoline
(RFG)and anti-dumping program. You may download our registration forms at *http://www.epa.gov/otaq/regs/fuels/rfgforms.htm.* These forms are well known in the regulated community and are very simple to fill out. Information requested includes company and facility names, addresses, and the identification of a contact person with telephone number and e-mail address. Registrations never expire and do not have to be renewed. However, all registered parties are responsible for notifying us of any change to their company or facility information. 3. How Do I Know I Am Properly Registered With EPA? Upon receipt of a completed registration form, we will provide you with a unique 4-digit company identification number and a unique 5-digit facility identification number. These numbers will appear in compliance reports and, in the case of renewable fuel producers and importers, they will be incorporated in the unique RINs they generate for each batch of renewable fuel. Timely registration is important because you cannot generate or handle transactions involving RINs until you have registered and received your registration numbers from us. It is advisable to register as soon as possible if you believe you will be engaged in activities that may require registration under the RFS program. Registration can occur any time following signature of this final rule. If you are already registered under another fuels program, such as RFG and anti-dumping or diesel sulfur, then you do not have to register again. You will use the same company and facility identification number you are currently using for RFS reporting. Parties in this situation may contact the Agency for confirmation or clarification of the appropriate registration numbers to use. As noted above, registrations never expire, but you are responsible for keeping the information we have up to date. If you have previously registered with us but have not had to report until now, then you may wish to contact the person listed on our renewable fuels Web page ( *http://www.epa.gov/otaq/renewablefuels/index.htm* ) in order to confirm the information in your registration file. 4. How Are Small Volume Domestic Producers of Renewable Fuels Treated for Registration Purposes? Small volume domestic producers of renewable fuels are those who produce less than 10,000 gallons per year or who import less than 10,000 gallons per year. These parties are not required to register if they do not wish to generate RINs. If a small volume domestic producer of renewable fuels wishes to generate RINs, then that party must register and comply with all recordkeeping and reporting requirements. C. Reporting 1. Who Must Report Under the RFS Program? Obligated parties, exporters of renewable fuel, producers and importers of renewable fuel, and any party who owns either assigned or unassigned RINs such as marketers or brokers must submit periodic reports to us covering RIN generation, RIN use, and RIN transactions. 2. What Reports Are Required Under the RFS Program? There are four basic reports under the RFS program. The first report is an annual compliance demonstration report that is required to be submitted by obligated parties and exporters of renewable fuel. This report provides the RFS compliance demonstration and is required to be submitted on an annual basis. It is focused on calculating the RVO, indicating RINs used for compliance, and determining any deficit carried over. The second report is a quarterly RIN generation report that is required to be submitted by producers and importers of renewable fuel. This report is focused on providing information on all batches of renewable fuel produced and imported and all RINs generated. The third report is a RIN transaction report that is required to be submitted by any party that owns RINs, including RIN marketers and brokers, as well as obligated parties, exporters, and renewable fuel producers and importers. This report is focused on providing information on individual RIN purchases, RIN sales, retired RINs, and expired RINs. 41 A separate RIN transaction report is required to be submitted for each RIN purchase and sale, and for each retired or expired RIN, and must be submitted by the end of the quarter in which the activity occurred. The purpose of the RIN transaction report is to document the ownership and transfer of RINs, and to track expired and retired RINs. This report is necessary because compliance with the RVO is primarily demonstrated through self-reporting of RIN trades and therefore we must be able to link transactions involving each unique RIN in order to verify compliance. We will be able to import reports into our compliance database and match RINs to transactions across their entire journey from generation to use. As with our other 40 CFR part 80 compliance-on-average and credit trading programs, many potential violations are expected to be self-reported. 41 In this final rule, we have clearly distinguished expired RINs, which are no longer valid due to the passage of time, from retired RINs, which are RINs no longer valid due to the reportable spillage of their assigned volumes under § 80.1132, RINs used to satisfy an enforcement action, or RINs used to effect an import volume correction under § 80.1166(k). Rather than leaving retired RINs under “any additional information that the Administrator may require,” we have specifically addressed them in this final rule. We believe it is useful to specifically distinguish between retired and expired RINs because it will be easier for us to determine whether a report is complete and to quality assure and check reported information by applying a consistent reporting distinction between expired and retired RINs. The fourth report is a quarterly gallon-RIN activity report that also is required to be submitted by *any* party that owns RINs. This report is focused on the total number of gallon-RINs owned at the start and end of the quarter, and the total number of gallon-RINs purchased, sold, retired and expired during the quarter. This report also requires information on end-of-quarter renewable fuel volumes. 3. What Are the Specific Reporting Items for the Various Types of Parties Required To Report? The following table summarizes the information to be submitted in each type of report by the type of regulated party: Table IV.C.3-1.—Information Contained in Reports by Regulated Party * Type of report Obligated parties Exporters of renewable fuel Producers and importers of renewable fuel Other parties who own RINS Annual Compliance Demonstration Report • Calculation of RVO • List of RINs used for compliance • Calculation of deficit carryover • Calculation of RVO • List of RINS used for compliance • Calculation of deficit carryover No report No report. Quarterly RIN Generation Report No report No report • Volume of each batch produced or imported • RINs generated for each batch • Volume of denaturant and applicable equivalence value of each batch No report. RIN Transaction Report Separate report for each transaction: • RIN purchase • RIN sale • Expired RIN • Retired RIN Separate report for each transaction: • RIN purchase • RIN sale • Expired RIN • Retired RIN Separate report for each transaction: • RIN purchase • RIN sale • Expired RIN • Retired RIN Separate report for each transaction: • RIN purchase. • RIN sale. • Expired RIN. • Retired RIN. Quarterly gallon-RIN Activity Report • Number of gallon-RINs* owned at start of quarter • Number of gallon-RINs purchased • Number of gallon-RINs sold • Number of gallon-RINs retired • Number of gallon-RINs expired (4th quarter only) • Number of gallon-RINs at end of quarter • Volume
(gals)of renewable fuel owned at end of quarter • Number of gallon-RINs owned at start of quarter • Number of gallon-RINs purchased • Number of gallon-RINs sold • Number of gallon-RINs retired • Number of gallon-RINS expired (4th quarter only) • Number of gallon-RINs at end of quarter • Volume
(gals)of renewable fuel owned at end of quarter • Number of gallon-RINs owned at start of quarter • Number of gallon-RINs purchased • Number of gallon-RINs sold • Number of gallon-RINs retired • Number of gallon-RINs expired (4th quarter only) • Number of gallon-RINs at end of quarter • Volume
(gals)of renewable fuel owned at end of quarter • Number of gallon-RINs owned at start of quarter. • Number of gallon-RINs purchased. • Number of gallon-RINs sold. • Number of gallon-RINs retired. • Number of gallon-RINs expired (4th quarter only). • Number of gallon-RINs at end of quarter. • Volume
(gals)of renewable fuel owned at end of quarter. * A gallon-RIN is a RIN that represents an individual gallon of renewable fuel. See § 80.1101. 4. What Are the Reporting Deadlines? In the proposed rule, we had requested comment on whether reporting should be annual or quarterly. After consideration of comments received, we have determined that each RIN transaction report must be submitted by the end of the quarter in which the transaction occurred, and the gallon-RIN activity report should be submitted quarterly. Quarterly reporting is better because it provides us with the information necessary to confirm the validity and legitimacy of RINs prior to their use in compliance. Additionally, quarterly reporting enables EPA to enforce the RIN/inventory balance requirements for producers and marketers of renewable fuels. The annual compliance demonstration for obligated parties must be submitted by February 28th for the prior calendar year. For the RIN transaction and quarterly gallon-RIN activity reports, the following schedule applies to all reporting parties: Table IV.C.4-1.—Quarterly Reporting Schedule for RFS Program Quarter covered by quarterly report Due date for quarterly report January-March May 31. April-June August 31. July-September November 30. October-December February 28. In the first year of the RFS program only, obligated parties and exporters are given an extra quarter to submit their list of RINs used to demonstrate compliance. This information must be reported by May 31, 2008 for calendar year 2007. All other reporting follows the schedule indicated above. 5. How May I Submit Reports to EPA? We will use a simplified and secure method of reporting via the Agency's Central Data Exchange (CDX). CDX permits us to accept reports that are electronically signed and certified by the submitter in a secure and robustly encrypted fashion. Using CDX will eliminate the need for wet ink signatures and will reduce the reporting burden on regulated parties. Guidance for reporting will be issued before implementation and will contain specific instructions and formats consistent with provisions in this final rule. The guidance will be posted on our renewable fuels Web page: * http:// www.epa.gov/otaq/renewablefuels/index.htm. * We will accept electronic reports generated in virtually all commercially available spreadsheet programs and will even permit parties to submit reports in comma delimited text, which can be generated with a variety of basic software packages. CDX will confirm delivery of your report. As described below with regard to recordkeeping, you must retain copies of all items submitted to us for five
(5)years. 6. What Does EPA Do With the Reports it Receives? In order to permit maximum flexibility in meeting the RFS program requirements, we must track activities involving the creation and use of RINs, as well as any transactions such as purchase or sale of RINs. Reports will be imported into a compliance database managed by EPA's Office of Transportation and Air Quality and will be reviewed for completeness and for potential violations. It is important to keep your company contact updated (this is an item on the registration form), because we may need to speak to that person about any problems with a report submitted. Potential violations will be referred to EPA enforcement personnel. 7. May I Claim Information in Reports as CBI and How Will EPA Protect it? You may claim information submitted to us as confidential business information (CBI). Please be sure to follow all reporting guidance and clearly mark the information you claim as proprietary. We will treat information covered by such a claim in accordance with the regulations at 40 CFR part 2 and other Agency procedures for handling proprietary information. 8. How Are Spilled Volumes With Associated Lost RINs To Be Handled in Reports? Since spills can happen whenever renewable fuel with assigned RINs is held, owners have two options if the spill causes their organization to be out of compliance. The owners of the spilled fuel may either retire RINs lost in reported spills or purchase and sell a volume of renewable fuel equal to the reported volume and not associated with RINs in order to meet compliance. Reportable spills for the purposes of this rule refers to spills of renewable fuel with assigned RINs and a requirement by a federal, state, or local authority to report said spills. The party that owns the spilled renewable fuel must retire a number of gallon-RINs corresponding to the volume of spilled renewable fuel multiplied by its equivalence value. If the equivalence value for the spilled volume may be determined based on its composition, then the appropriate equivalence value shall be used. If the equivalence value for the spilled volume cannot be determined, the equivalence value is 1.0. In the case that the fuel must be reported in pounds rather than gallons, the party that reported the spill should use the best available conversion for converting the volume into gallons. In the event that volume is spilled in transport, the owner of the RINs will need to request a copy of the spill report from the party that reported the spill. D. Recordkeeping 1. What Types of Records Must Be Kept? The recordkeeping requirements for obligated parties and exporters of renewable fuels support the enforcement of the use of RINs for compliance purposes. Records kept by parties are central to tracking individual RINs through the fungible distribution system after those RINs are assigned to batches of renewable fuel. Parties use invoices or other types of product transfer documentation, which are customarily generated and issued in the course of business and which are familiar to parties who transfer or receive fuel. Parties are afforded significant freedom with regard to the form these documents take, although they must travel in some manner (on paper or electronically) with the volume of renewable fuel being transferred. On each occasion any person transfers ownership of renewable fuels subject to this regulation, that transferor must provide the transferee with documents identifying the renewable fuel and containing the identifying information that includes: The name and address of the transferor and transferee, the EPA-issued company identification number of the transferor and transferee, the volume of renewable fuel that is being transferred, the date of transfer, and each associated RIN. These types of documents must be used by all parties in the distribution chain down to the point where the renewable fuel is blended into conventional gasoline or diesel. Except for transfers to truck carriers, retailers or wholesale purchaser-consumers, product codes may be used to convey the information required, as long as the codes are clearly understood by each transferee. However, the RIN must always appear in its entirety before it is separated from a batch, since it is a unique identification number that cannot be summarized by a shorter code. Parties must keep copies of all records for a period of not less than five
(5)years. In addition to documentation related to transfers, parties must keep information related to the sale, purchase, brokering and trading of RINs and copies of any reports they submit to us for compliance reports. For example, if a volume of fuel and its associated RINs are reported to us as lost due to spillage, documentation related to that spill must be retained for the five year period. Upon request, parties are responsible for providing records to the Administrator or the Administrator's authorized representative. 2. What Recordkeeping Requirements Are Specific to Producers of Cellulosic or Waste-Derived Ethanol? In addition to the records applicable to all ethanol producers, producers of cellulosic biomass or waste-derived ethanol must keep records of fuel use in order to ensure compliance with, and enforcement of, the definitions of these types of renewable fuel. Producers of cellulosic biomass or waste-derived ethanol must keep records of volume and types of all feedstocks purchased to ensure compliance with, and enforcement of, the feedstock aspect of the definitions of cellulosic biomass and waste-derived ethanol. In addition, producers of cellulosic biomass or waste-derived ethanol are required to arrange for an independent third party to review the ethanol producer's records and verify that the facility is, in fact, a cellulosic biomass or waste-derived ethanol production facility and that the ethanol producer is producing cellulosic biomass or waste-derived ethanol. The independent third party must be a licensed Professional Engineer (P.E.) in the chemical engineering field. Domestic ethanol producers are not required obtain prior approval of the independent third party P.E. or submit the engineering verification to EPA, however, the ethanol producer and the P.E. are required to keep records related to the required engineering verification and to produce them upon request of the Administrator or the Administrator's authorized representative. A foreign ethanol producer may apply to us to have its cellulosic biomass or waste-derived ethanol treated in the same manner as domestic cellulosic biomass or waste-derived ethanol under the RFS program. A foreign ethanol producer with an approved application will be required to comply with all of the requirements that apply to domestic ethanol producers, including registration, recordkeeping, reporting, attest engagements, and the independent third party verification discussed above. The attest engagements for a foreign ethanol producer must be conducted by a U.S. auditor (if not a U.S. based auditor, the auditor must be approved in advance by EPA). Similar to other fuels programs, the foreign ethanol producer will be required to comply with additional requirements designed to ensure that enforcement of the regulations at the foreign ethanol facility will not be compromised. The independent third party P.E. conducting the facility verification must be approved by EPA before the foreign entity will be allowed to treat its cellulosic biomass or waste-derived ethanol in the same manner as domestic producers. The foreign ethanol producer must arrange for the P.E. to inspect the facility and submit a report to us which describes the physical plant and its operation and includes documentation of the P.E.'s qualifications. The foreign ethanol producer must agree to provide access to EPA personnel for the purposes of conducting inspections and audits, post a bond, and arrange for an independent inspector to monitor ship loading and offloading records to ensure that volumes of ethanol do not change from port of shipping to port of entry. The independent inspector must be approved by EPA prior to the shipment of any ethanol designated by the foreign ethanol producer as ethanol which is to be treated as cellulosic biomass or waste-derived ethanol. Cellulosic biomass or waste-derived ethanol produced by a foreign ethanol producer must be identified as such on product transfer documents that accompany the ethanol to the importer. (These additional provisions for foreign ethanol producers are contained in § 80.1166.) The provisions for foreign ethanol producers are optional and are available only to foreign producers of cellulosic biomass or waste-derived ethanol. Ethanol or other renewable fuels produced and exported to the United States by other foreign producers are regulated through the importer. An importer that receives ethanol identified as cellulosic biomass or waste-derived ethanol produced by a foreign producer with an approved application would not assign RINs to the ethanol, as RINs for such ethanol will be assigned by the foreign ethanol producer. The importer, like any other marketer, would transfer the RINs assigned by the foreign producer with a volume of ethanol and report the transactions to us. E. Attest Engagements 1. What Are the Attest Engagement Requirements Under the RFS Program? Attest engagements are similar to financial audits and consist of an independent, professional review of compliance records and reports. Similar to other fuels programs, the RFS program requires reporting parties to arrange for annual attest engagements to be conducted by an auditor that is “independent” under the criteria specified in the regulations. We believe that the attest engagements provide an appropriate and useful tool for verifying the accuracy of the information reported to us. Attest engagements are performed in accordance with standard procedures and standards established by the American Institute of Certified Public Accountants and the Institute of Internal Auditors. The attest engagement consists of an outside certified public accountant
(CPA)or certified independent auditor
(CIA)following agreed upon procedures to determine whether underlying records, reported items, and transactions agree, and issuing a report as to their findings. Attest engagements are performed on an annual basis. 2. Who Is Subject to the Attest Engagement Requirements for the RFS Program? Obligated parties, producers, exporters and importers of renewable fuel, and any party who own RINs are all subject to the attest engagement requirements. 3. How Are the Attest Engagement Requirements in This Final Rule Different From Those Proposed? We had proposed that obligated parties, exporters, and renewable fuels producers be subject to attest engagement requirements. We received several comments on this proposal. Some commenters suggested that the attest engagements should be required for renewable fuels producers and importers, but not for obligated parties. These commenters believe that attest engagements are needed for renewable fuel producers and importers in order to verify reported production and RIN volumes, whereas we can monitor compliance by obligated parties by cross-checking their reports regarding RIN transactions and use with the reports from other parties. These commenters also believe that the information required by obligated parties under the RFS program is not such that an attest engagement is needed because the rule does not require verification of raw data as with other fuels programs. We have considered these comments but continue to believe that the attest engagements are an appropriate means of verifying the accuracy of the information reported to us by obligated parties. In addition to documentation of RIN transactions and use, the reports include information on production and import volumes and calculation of the party's RFS obligation. We believe that attest engagements are necessary in order to verify that the underlying data regarding production and import volumes and RFS obligation, as well as the underlying data regarding RIN transactions and use, support the information included in the reports. As a result, the final rule includes an attest engagement requirement for obligated parties. We also received several comments that the attest engagement auditor should be required to examine only representative samples of the party's RIN transaction documents rather than the documents for each RIN transaction, as required in the proposed regulations. We agree that examination of representative samples of RIN transaction documents would provide sufficient oversight and that the requirement included in the proposed regulations may be unnecessarily burdensome. As a result, the attest engagement provisions have been modified to require the auditor to examine only representative samples of RIN transaction documents. However, in the case of attest engagements applied to RIN generation by producers or importers of renewable fuel, or the use of RINs for compliance purposes by obligated parties or exporters, the auditor must examine documentation for all RINs generated or used. We believe this requirement is necessary to ensure that obligated parties and exporters are meeting their RFS obligation and that ethanol producers and importers are assigning RINs to each batch of renewable fuel produced or imported as required under the regulations. The proposed attest engagement regulations at § 80.1164(b) did not include importers of renewable fuels. One commenter pointed out these procedures should apply to both renewable fuels producers and importers. Renewable fuel importers have the same reporting requirements as renewable fuel producers, and, therefore, there is the same need for verification of the information given on the reports through attest engagements. It was an inadvertent oversight that renewable fuel importers were not included in the parties required to comply with the attest engagement procedures in proposed § 80.1164(b), and that applying the requirements in § 80.1164(b) to renewable fuel importers is a logical outgrowth of the proposed regulations. As a result, the regulations have been modified to include renewable fuel importers in the parties required to comply with the attest procedures in § 80.1164(b). In addition to obligated parties, exporters and renewable fuel producers and importers, we believe that an attest engagement requirement is necessary for any party who takes ownership of a RIN. As discussed above, attest engagements provide an appropriate and useful tool for verifying the accuracy of the information reported to us. Like obligated parties and renewable fuel producers and importers, the final rule requires RIN owners to submit information regarding RIN transaction activity to us. We believe that attest engagement audits are necessary to verify the accuracy of the information included in these reports. Therefore, this final rule includes an attest engagement requirement for RIN owners who are not obligated parties or renewable fuel producers or importers. We believe that inclusion of the requirement in the final rule is a logical outgrowth of the proposed attest engagement requirements for other parties who are required to submit similar information regarding RIN transaction activity to us. V. What Acts Are Prohibited and Who Is Liable for Violations? The prohibition and liability provisions applicable to the RFS program are similar to those of other gasoline programs. The final rule identifies certain prohibited acts, such as a failure to acquire sufficient RINs to meet a party's renewable fuel obligation (RVO), producing or importing a renewable fuel without properly assigning a RIN, creating, transferring or using invalid RINs, improperly transferring renewable fuel volumes without RINs, improperly separating RINs from renewable fuel, retaining more RINs during a quarter than the party's inventory of renewable fuel, or transferring RINs that are not identified by proper RIN numbers. Any person subject to a prohibition will be held liable for violating that prohibition. Thus, for example, an obligated party will be liable if the party fails to acquire sufficient RINs to meet its RVO. A party who produces or imports renewable fuels will be liable for a failure to properly assign RINs to batches of renewable fuel produced or imported. A renewable fuels marketer will be liable for improperly transferring renewable fuel volumes without RINs or retaining more RINs during a quarter than the party's inventory of renewable fuels. Any party may be liable for creating, transferring, or using an invalid RIN, or transferring a RIN that is not properly identified. In addition, any person who is subject to an affirmative requirement under the RFS program will be liable for a failure to comply with the requirement. For example, an obligated party will be liable for a failure to comply with the annual compliance reporting requirements. A renewable fuel producer or importer will be liable for a failure to comply with the applicable renewable fuel batch reporting requirements. Any party subject to recordkeeping or product transfer document requirements would be liable for a failure to comply with these requirements. Like other EPA fuels programs, the final rule provides that a party who causes another party to violate a prohibition or fail to comply with a requirement may be found liable for the violation. The Energy Act amended the penalty and injunction provisions in section 211(d) of the Clean Air Act to apply to violations of the renewable fuels requirements in section 211(o). 42 Accordingly, under the final rule, any person who violates any prohibition or requirement of the RFS program may be subject to civil penalties for every day of each such violation and the amount of economic benefit or savings resulting from the violation. Under the final rule, a failure to acquire sufficient RINs to meet a party's renewable fuels obligation will constitute a separate day of violation for each day the violation occurred during the annual averaging period. 42 Section 1501(b) of the Energy Policy Act of 2005. Because there are no standards under the RFS rule that may be measured downstream, we believe that a presumptive liability scheme, i.e., a scheme in which parties upstream from the facility where the violation is found are presumed liable for the violation, would not be applicable under the RFS program. As a result, the RFS rule does not contain such a scheme. The regulations prohibit any party from creating, transferring or using invalid RINs. These invalid RIN provisions apply regardless of the good faith belief of a party that the RINs are valid. These enforcement provisions are necessary to ensure the RFS program goals are not compromised by illegal conduct in the creation and transfer of RINs. Any obligated party that reports the use of invalid RINs to meet its renewable fuels obligation may be liable for a regulatory violation for use of invalid RINs. If the obligated party fails to meet its renewable fuels obligation without the invalid RINs, the party may also be liable for not meeting its renewable fuels obligation. In addition, the transfer of invalid RINs is prohibited, so that any party or parties that transfer invalid RINs may be liable for a regulatory violation for transferring the invalid RINs. In a case where invalid RINs are transferred and used, EPA normally will hold each party that committed a violation responsible, including both the user and the transferor of the invalid RINs. For this reason, obligated parties and RIN brokers should use good business judgment when deciding whether to purchase RINs from any particular seller and should consider including prudent business safeguards in RIN transactions, such as requiring RIN sellers to sign contracts with indemnity provisions to protect the purchaser in the event penalties are assessed because we find the RINs are invalid. Similarly, parties that sell RINs should take steps to ensure any RINs that are sold were properly created to avoid penalties that result from the transfer of invalid RINs. As in other motor vehicle fuel credit programs, the regulations address the consequences if an obligated party is found to have used invalid RINs to demonstrate compliance with its RVO. In this situation, the obligated party that used the invalid RINs will be required to deduct any invalid RINs from its compliance calculations. As discussed above, the obligated party will be liable for not meeting its renewable fuels obligation if the remaining number of valid RINs is insufficient to meet its RVO, and the obligated party may be subject to monetary penalties if it used invalid RINs in its compliance demonstration. In determining an appropriate penalty, EPA will consider a number of factors, including whether the obligated party did in fact procure sufficient valid RINs to cover the deficit created by the invalid RINs. A penalty may include both the economic benefit of using invalid RINs and a gravity component. Although an obligated party may be liable for a violation if it uses invalid RINs for compliance purposes, we normally will look first to the generator or seller of the invalid RINs both for payment of penalty and to procure sufficient valid RINs to offset the invalid RINs. However, if EPA is unable to obtain relief from that party, attention will turn to the obligated party who may then be required to obtain sufficient valid RINs to offset the invalid RINs. We received several comments on the prohibition regarding use of invalid RINs. Some commenters believe that an obligated party that uses RINs which are later found to be invalid should be given an opportunity to “cure” the shortfall caused by the invalid RINs without penalty. As indicated above, a penalty for a good faith purchaser is not automatic. Where an invalid RIN was created by another party, such as the producer or marketer of the renewable fuel, the party responsible for the existence of the invalid RIN would be liable and would be required to purchase a RIN to make up for the invalid RIN and pay an appropriate penalty. If the responsible party cannot be identified or is out of business, or if EPA is otherwise unable to obtain relief from the party, then the obligated party that used the RIN would be required to purchase a RIN to make up for the invalid RIN. However, any penalty for a good faith purchaser would likely be small, particularly where EPA is able to obtain relief from the party that was responsible for the invalid RIN. Where a RIN was originally believed to be valid but is later found to be invalid, whether a current year RIN may be used to make up for the prior-year invalid RIN would be determined in the context of the enforcement action. Another commenter suggested that an obligated party should not be liable for a violation unless the party knowingly used the invalid RINs to demonstrate compliance. Where the suspect RINs are later proved to be valid, the party should be able to use the RINs in the subsequent year regardless of the year of generation or any rollover cap. For the reasons stated above, we believe that it is appropriate to hold an obligated party responsible for using invalid RINs even where the party in good faith believed the RINs to be valid. Normally, suspect RINs will be not be replaced until the RINs are proved to be invalid. In the unlikely circumstance that a RIN is first determined to be invalid and then later found to be valid, the ability to use the RIN in a subsequent year would be determined in the context of the enforcement action. Finally, parties that are predominately renewable fuel producers or importers, but which must be designated as obligated parties due to the production or importation of a small amount of gasoline, should not be able to separate RINs from all renewable fuels that they own. To address such circumstances, we are prohibiting obligated parties from separating RINs that they generate from volumes of renewable fuel in excess of their RVO. However, obligated parties must separate any RINs generated by other parties from renewable fuel if they own the renewable fuel. VI. Current and Projected Renewable Fuel Production and Use While the definition of renewable fuel does not limit compliance with the standard to any one particular type of renewable fuel, ethanol is currently the most prevalent renewable fuel blended into gasoline today. Biodiesel represents another renewable fuel which, while not as widespread as ethanol use (in terms of volume), has been increasing in production capacity and use over the last several years. This section provides a brief overview of the ethanol and biodiesel industries today and how they are projected to grow into the future. A. Overview of U.S. Ethanol Industry and Future Production/Consumption 1. Current Ethanol Production As of October 2006, there were 110 ethanol production facilities operating in the United States with a combined production capacity of approximately 5.2 billion gallons per year. 43 All of the ethanol currently produced comes from grain or starch-based feedstocks that can easily be broken down into ethanol via traditional fermentation processes. The majority of ethanol (almost 92 percent by volume) is produced exclusively from corn. Another 7 percent comes from a blend of corn and/or similarly processed grains (milo, wheat, or barley) and less than 1 percent is produced from waste beverages, cheese whey, and sugars/starches combined. A summary of ethanol production by feedstock is presented in Table VI.A.1-1. 43 The October 2006 ethanol production capacity baseline was generated based on the June 2006 NPRM plant list and updated on October 18, 2006 based on a variety of data sources including: Renewable Fuels Association (RFA), Ethanol Biorefinery Locations (updated October 16, 2006); Ethanol Producer Magazine (EPM), plant list (downloaded October 18, 2006) and monthly publications (June 2006 through October 2006); ICF International, Ethanol Industry Profile (September 30, 2006); BioFuels Journal, News & Information for the Ethanol and BioFuels Industries (breaking news posted June 16, 2006 through October 18, 2006); and ethanol producer Web sites. The baseline includes small-scale ethanol production facilities as well as former food-grade ethanol plants that have since transitioned into the fuel-grade ethanol market. Where applicable, current ethanol plant production levels have been used to represent plant capacity, as nameplate capacities are often underestimated. This analysis does not consider ethanol plants that may be located in the Virgin Islands or U.S. territories. Table VI.A.1-1.—2006 U.S. Ethanol Production by Feedstock Plant feedstock Capacity MMgy Percent of capacity Number of plants Percent of plants Cheese Whey 8 0.1 2 1.8 Corn a 4,780 91.6 90 81.8 Corn, Barley 40 0.8 1 0.9 Corn, Milo b 244 4.7 8 7.3 Corn, Wheat 90 1.7 2 1.8 Milo, Wheat 40 0.8 1 0.9 Sugars, Starches 2 0.0 1 0.9 Waste Beverages c 16 0.3 5 4.5 Total 5,218 100.0 110 100.0 a Includes two facilities processing seed corn and another facility processing corn which intends to transition to corn stalks, switchgrass, and biomass in the future. b Includes one facility procesisng small amounts of molasses in addition to corn and milo. c Includes two facilities processing brewery waste. There are a total of 102 plants processing corn and/or other similarly processed grains. Of these facilities, 92 utilize dry-milling technologies and the remaining 10 plants rely on wet-milling processes. Dry mill ethanol plants grind the entire kernel and produce only one primary co-product: Distillers' grains with solubles (DGS). The co-product is sold wet
(WDGS)or dried
(DDGS)to the agricultural market as animal feed. In contrast to dry mill plants, wet mill facilities separate the kernel prior to processing and in turn produce other co-products (usually gluten feed, gluten meal, and oil) in addition to DGS. Wet mill plants are generally more costly to build but are larger in size on average. As such, nearly 22 percent of the current overall ethanol production comes from the 10 previously-mentioned wet mill facilities. The remaining 8 plants which process waste beverages, cheese whey, or sugars/starches, operate differently than their grain-based counterparts. These facilities do not require milling and instead operate a simpler enzymatic fermentation process. In addition to grain and starch-to-ethanol production, another method exists for producing ethanol from a more diverse feedstock base. This process involves converting cellulosic materials such as bagasse, wood, straw, switchgrass, and other biomass into ethanol. Cellulose consists of tightly-linked polymers of starch, and production of ethanol from it requires additional steps to convert these polymers into fermentable sugars. Scientists are actively pursuing acid and enzyme hydrolysis as well as gasification to achieve this goal, but the technologies are still not fully developed for large-scale commercial production. As of October 2006, the only known cellulose-to-ethanol plant in North America was Iogen in Canada, which produces approximately one million gallons of ethanol per year from wood chips. Several companies have announced plans to build cellulose-to-ethanol plants in the U.S., but most are still in the research and development or pre-construction planning phases. The majority of the plans involve converting bagasse, rice hulls, wood, switchgrass, corn stalks, and other agricultural waste or biomass into ethanol. For a more detailed discussion on future cellulosic ethanol plants and production technologies, refer to RIA Sections 1.2.3.6 and 7.1.2, respectively. Ethanol production is a relatively resource-intensive process that requires the use of water, electricity, and steam. Steam needed to heat the process is generally produced onsite or by other dedicated boilers. Of today's 110 ethanol production facilities, 101 burn natural gas, 7 burn coal, 1 burns coal and biomass, and 1 burns syrup from the process to produce steam. 44 Our research suggests that 11 plants currently utilize cogeneration or combined heat and power
(CHP)technology, although others may exist. CHP is a mechanism for improving overall plant efficiency. Whether owned by the ethanol facility, their local utility, or a third party; CHP facilities produce their own electricity and use the waste heat from power production for process steam, reducing the energy intensity of ethanol production. A summary of the energy sources and CHP technology utilized by today's ethanol plants is found in Table VI.A.1-2. 44 Facilities were assumed to burn natural gas if the plant fuel type was not mentioned or unavailable. Table VI.A.1-2.—2006 U.S. Ethanol Production by Energy Source Plant energy source Capacity MMgy Percent of capacity Number of plants Percent of plants CHP tech. Coal 1,042 20.0 7 6.3 2 Coal, Biomass 50 1.0 1 0.9 0 Natural Gas a 4,077 78.1 101 91.8 9 Syrup 48 0.9 1 0.9 0 Total 5,218 100.0 110 100.0 11 a Includes three facilities burning natural gas which intend to transition to coal or biomass in the future. The majority of domestic ethanol is currently produced in the Midwest within PADD 2—where most of the corn is grown. Of the 110 U.S. ethanol production facilities, 100 are located in PADD 2. As a region, PADD 2 accounts for 96 percent (or over five billion gallons) of the annual domestic ethanol production, as shown in Table VI.A.1-3. Table VI.A.1-3.—2006 U.S. Ethanol Production by PADD PADD Capacity MMgy Percent of capacity Number of plants Percent of plants PADD 1 0.4 0.0 1 0.9 PADD 2 5,012 96.0 100 90.9 PADD 3 30 0.6 1 0.9 PADD 4 105 2.0 4 3.6 PADD 5 71 1.4 4 3.6 Total 5,218 100.0 110 100.0 Leading the Midwest in ethanol production are Iowa, Illinois, Nebraska, Minnesota, and South Dakota with a combined capacity of nearly four billion gallons per year. Together, these five states' 70 ethanol plants account for 76 percent of the total domestic product. However, although the majority of ethanol production comes from PADD 2, there are a growing number of plants located outside the traditional corn belt. In addition to the 15 states comprising PADD 2, ethanol plants are currently located in California, Colorado, Georgia, New Mexico, and Wyoming. Some of these facilities ship in feedstocks (namely corn) from the Midwest, others rely on locally grown/produced feedstocks, while others rely on a combination of both. The U.S. ethanol industry is currently comprised of a mixture of corporations and farmer-owned cooperatives (co-ops). More than half (or 60) of today's plants are owned by corporations and, on average, these plants are larger in size than farmer-owned co-ops. Accordingly, company-owned plants account for almost 64 percent of the total U.S. ethanol production capacity. Further, more than 50 percent of the total domestic product comes from plants owned by just 6 different companies—Archer Daniels Midland, Broin, VeraSun, Hawkeye Renewables, Global/MGP Ingredients, and Aventine Renewable Energy. 45 45 Includes Broin's minority ownership in 18 U.S. ethanol plants. 2. Expected Growth in Ethanol Production Over the past 25 years, domestic fuel ethanol production has steadily increased due to environmental regulation, federal and state tax incentives, and market demand. More recently, ethanol production has soared due to the phase out of MTBE, an increasing number of state ethanol mandates, and elevated crude oil prices. As shown in Figure VI.A.2-1, over the past three years, domestic ethanol production has nearly doubled from 2.1 billion gallons in 2002 to 4.0 billion gallons in 2005. For 2006, the Renewable Fuels Association is anticipating about 4.7 billion gallons of domestic ethanol production. 46 46 Based on RFA comments received in response to the proposed rulemaking, 71 FR 55552 (September 22, 2006). ER01MY07.047 EPA forecasts that domestic ethanol production will continue to grow into the future. In addition to the past impacts of federal and state tax incentives, as well as the more recent impacts of state ethanol mandates and the removal of MTBE from all U.S. gasoline, crude oil prices are expected to continue to drive up demand for ethanol. As a result, the nation is on track to exceed the renewable fuel volume requirements contained in the Act. Today's ethanol production capacity (5.2 billion gallons) is already exceeding the 2007 renewable fuel requirement (4.7 billion gallons). In addition, there is another 3.4 billion gallons of ethanol production capacity currently under construction. 47 A summary of the new construction and plant expansion projects currently underway (as of October 2006) is found in Table VI.A.2-1. 47 Under construction plant locatons, capacities, feedstocks, and energy sources as well as planned/proposed plant locations and capacities were derived from a variety of data soruces including Renewable Fuels Association (RFA), Ethanol Biorefinery Locations (updated October 16, 2006); Ethanol Producer Magazine (EPM), under construction plant list (downloaded October 18, 2006) and monthly publications (June 2006 through October 2006); ICF International, Ethanol Industry Profile (September 30, 2006); BioFuels Journal, News & Information for the Ethanol and BioFuels Industries (breaking news posted June 16, 2006 through October 18, 2006); and ethanol producer Web sites. This analysis does not consider ethanol plants under construction or planned for the Virgin Islands or U.S. territories. Table VI.A.2-1.—Under Construction U.S. Ethanol Production Capacity PADD Oct. 2006 baseline MMgy Plants Under const. MMgy a Plants Base + under const. MMgy a Plants PADD 1 0.4 1 115 1 115 2 PADD 2 5,012 100 2,764 39 7,776 139 PADD 3 30 1 230 3 260 4 PADD 4 105 4 50 1 155 5 PADD 5 71 4 198 3 269 7 Total 5,218 110 3,357 47 8,575 157 a Includes plant expansions. A select group of builders, technology providers, and construction contractors are completing the majority of the construction projects described in Table VI.A.2-1. As such, the completion dates of these projects are staggered over approximately 18 months, resulting in the gradual phase-in of ethanol production shown in Figure VI.A.2-2. 48 48 Construction timelines based on information obtained from press releases and ethanol producer Web sites. ER01MY07.048 As shown in Table VI.A.2-1 and Figure VI.A.2-2, once all the construction projects currently underway are complete (estimated by March 2008), the resulting U.S. ethanol production capacity would be about 8.6 billion gallons. Without even considering forecasted biodiesel production (described below in Section VI.B.1), this would be more than enough renewable fuel to satisfy the 2012 RFS requirements (7.5 billion gallons). However, ethanol production is expected to continue to grow. There are more and more ethanol projects being announced each day. These potential projects are at various stages of planning from conducting feasibility studies to gaining local approval to applying for permits to financing/fundraising to obtaining contractor agreements. Together these potential projects could result in an additional 21 billion gallons of ethanol production capacity as shown in Table VI.A.2-2. Table VI.A.2-2.—Other Potential U.S. Ethanol Production Capacity PADD Base + under const. MMgy a Plants Planned MMgy a Plants Proposed MMgy a Plants PADD 1 115 2 548.0 8 934 21 PADD 2 7,776 139 4,633 44 11,722 136 PADD 3 260 4 250 4 876 14 PADD 4 155 5 100 1 783 14 PADD 5 269 7 232 8 775 23 Subtotal 8,575 157 5,763 65 15,090 208 Total b 14,339 222 29,428 430 a Includes plant expansions. b Total including existing plus under construction plants. Although there is clearly a great potential for ethanol production growth, it is highly unlikely that all the announced projects would actually reach completion in a reasonable amount of time, or at all, considering the large number of projects moving forward. Since there is no precise way to know exactly which plants will come to fruition in the future, we have chosen to focus our subsequent discussion on forecasted ethanol production on plants which are likely to be online by 2012. 49 This includes existing plants as well as projects which are under construction (refer to Table VI.A.2-1) or in the final planning stages (denoted as “planned” in Table VI.A.2-2). The distinction between “planned” versus “proposed” is that as of October 2006 planned projects had completed permitting, fundraising/financing, and had builders assigned with definitive construction timelines whereas proposed projects did not. 49 A more detailed summary of the plants we considered is found in a March 5, 2007 note to the docket titled: RFS Industry Characterization—Ethanol Production. Table VI.A.2-3.—Forecasted 2012 Ethanol Production by PADD PADD Capacity MMgy Percent of capacity Number of plants Percent of plants PADD 1 663 4.6 10 4.5 PADD 2 12,409 86.5 183 82.4 PADD 3 510 3.6 8 3.6 PADD 4 255 1.8 6 2.7 PADD 5 501 3.5 15 6.8 Total 14,339 100.0 222 100.0 As shown above in Table VI.A.2-3, once all the under construction and planned projects are complete the resulting ethanol production capacity would be 14.3 billion gallons. The majority of which would still originate from PADD 2. This volume, expected to be online by 2012, exceeds the EIA AEO 2006 demand estimate (9.6 billion gallons by 2012, discussed more in RIA Section 2.1). The forecasted growth would nearly triple today's production capacity and greatly exceed the 2012 RFS requirement (7.5 billion gallons). While our forecast represents ethanol production capacity (actual production could be lower), we believe it is still a good indicator of what domestic ethanol production could look like in the future. In addition, we predict that domestic ethanol production will continue to be supplemented by imports in the future. According to a current report by F.O. Licht, U.S. net import demand is estimated to be around 300 million gallons per year by 2012, being supplied primarily through the Caribbean Basin Initiative (CBI), with some direct imports from Brazil during times of shortfall or high price. For more information on ethanol imports, refer to RIA Section 1.5. Of the 112 forecasted new ethanol plants (47 under construction and 65 planned), 106 would rely on grain-based feedstocks. More specifically, 89 would rely exclusively on corn, 13 would process a blend of corn and/or similarly processed grains (milo or wheat), 3 would process molasses, and 1 would process a combination of molasses and sweet sorghum (milo). Of the remaining six plants (all in the planned stage), four would process cellulosic biomass feedstocks and two would start off processing corn and later transition to cellulosic materials. Of the four dedicated cellulosic plants, one would process bagasse, one would process a combination of bagasse and wood, and two would process biomass. Of the two transitional corn/cellulosic plants, one would ultimately process a combination of bagasse, rice hulls, and wood and the other would ultimately process wood and other agricultural residues. In addition to the forecasted new plants, an existing corn ethanol plant plans to expand production and transition to corn stalks, switchgrass, and biomass in the future. A summary of the resulting overall feedstock usage (including current, under construction, and planned projects) is found in Table VI.A.2-4. Table VI.A.2-4.—Forecasted 2012 U.S. Ethanol Production by Feedstock Plant feedstock Capacity MMgy Percent of capacity Number of plants Percent of plants Bagasse 7 0.1 1 0.5 Bagasse, Wood 2 0.0 1 0.5 Bagasse, Wood, Rice Hulls a 108 0.8 1 0.5 Biomass 55 0.4 2 0.9 Cheese Whey 8 0.1 2 0.9 Corn b 12,495 87.1 178 80.2 Corn, Barley 40 0.3 1 0.5 Corn, Milo c 1,132 7.9 20 9.0 Corn, Wheat 235 1.6 3 1.4 Corn Stalks, Switchgrass, Biomass a 40 0.3 1 0.5 Milo, Wheat 40 0.3 1 0.5 Molasses d 52 0.4 4 1.8 Sugars, Starches 2 0.0 1 0.5 Waste Beverages e 16 0.1 5 2.3 Wood Agricultural Residues a 108 0.8 1 0.5 Total 14,339 100.0 222 100.0 a Facilities plan to start off processing corn. b Includes two facilities processing seed corn. c Includes one facility processing small amounts of molasses in addition to corn and milo. d Includes one facility planning to process sweet sorghum
(milo)in addition to molasses. e Includes two facilities processing brewery waste. Of the 112 forecasted new plants, 100 would burn some amount of natural gas—at least initially. More specifically, 91 plants would rely exclusively on natural gas; 2 would rely on a combination of natural gas, bran and biomass; 1 would burn a combination of natural gas, distillers' grains and syrup; and 6 would start off burning natural gas and later transition to coal. As for the remaining 12 plants, 3 would burn manure-derived methane (biogas); 7 would rely exclusively on coal; 1 would burn a combination of coal and biomass; and 1 would burn a combination of coal, tires and biomass. In addition to the new ethanol plants, three existing plants currently burning natural gas are predicted to transition to alternate boiler fuels in the future. More specifically, two plants plan to transition to biomass and one plans to start burning coal. Our research suggests that 7 of the new plants would utilize combined heat and power
(CHP)technology, although others may exist. Three of the new CHP plants would burn natural gas, three would burn coal, and one would burn a combination of coal, tires, and biomass. Among the existing CHP plants, two are predicted to transition from natural gas to coal or biomass at this time. Overall, the net number of CHP ethanol plants would increase from 11 to 18. A summary of the resulting overall plant energy source utilization is found below in Table VI.A.2-5. Table VI.A.2-5.—Forecasted 2012 U.S. Ethanol Production by Energy Source Plant energy source Capacity MMgy Percent of capacity Number of plants Percent of plants CHP tech. Biomass a 112 0.8 2 0.9 1 Coal b 2,095 14.6 21 9.5 6 Coal, Biomass 75 0.5 2 0.9 0 Coal, Biomass, Tires 275 1.9 1 0.5 1 Manure Biogas c 144 1.0 3 1.4 0 Natural Gas 11,275 78.6 189 85.1 10 Natural Gas, Bran, Biomass 264 1.8 2 0.9 0 Natural Gas, Distiller's Grain, Syrup 50 0.3 1 0.5 0 Syrup 49 0.3 1 0.5 0 Total 14,339 100.0 222 100.0 18 a Represents two existing natural gas-fired plants that plan to transition to biomass. b Includes two plants planning on burning lignite coal or coal lines. Includes one existing plant currently burning natural gas that plans to transition to coal. Includes six new plants that will start off burning natural gas and later transition to coal. c Includes one facility planning on burning cotton gin in addition to manure biogas. The Energy Policy Act of 2005 requires that 250 million gallons of the renewable fuel consumed in 2013 and beyond meet the definition of cellulosic biomass ethanol. The Act defines cellulosic biomass ethanol as ethanol derived from any lignocellulosic or hemicellulosic matter that is available on a renewable or recurring basis including dedicated energy crops and trees, wood and wood residues, plants, grasses, agricultural residues, fibers, animal wastes and other waste materials, and municipal solid waste. The term also includes any ethanol produced in facilities where animal or other waste materials are digested or otherwise used to displace 90 percent of more of the fossil fuel normally used in the production of ethanol. As shown in Table VI.A.2-4, there are seven ethanol plants planning to utilize cellulosic feedstocks in the future. These facilities have a combined ethanol production capacity of 320 million gallons per year. It is unclear whether these plants would be online and capable of producing 250 million gallons of ethanol by 2013 to meet the Act's cellulosic biomass ethanol requirement. However, as shown in Table VI.A.2-5, there are 12 facilities that burn or plan to burn waste materials to power their ethanol plants. Depending on how much fossil fuel is displaced, these facilities (with a combined ethanol production capacity of 969 million gallons per year) could also meet the definition of cellulosic biomass ethanol under the Act. Considering both feedstock and waste energy plants, the total cellulosic ethanol potential could be as high as 1.3 billion gallons. Even if only one fifth of this ethanol were to end up qualifying as cellulosic biomass ethanol or come to fruition by 2013, it would be more than enough to satisfy the 250 million gallon requirement specified in the Act. 50 50 We anticipate a ramp-up in cellulosic ethanol production in the years to come so that capacity exists to satisfy the Act's 2013 requirement (250 million gallons of cellulosic biomass ethanol). Therefore, for subsequent analysis purposes, we have assumed that 250 million gallons of ethanol would come from cellulosic biomass sources by 2012. 3. Current Ethanol and MTBE Consumption To understand the impact of the increased ethanol production/use on gasoline properties and in turn overall air quality, we first need to gain a better understanding of where ethanol is used today and how the picture is going to change in the future. As such, in addition to the production analysis presented above, we have completed a parallel consumption analysis comparing current ethanol consumption to future predictions. In the 2004 base case, 3.5 billion gallons of ethanol 51 and 1.9 billion gallons of MTBE 52 were blended into gasoline to supply the transportation sector with a total of 136 billion gallons of gasoline. 53 A breakdown of the 2004 gasoline and oxygenate consumption by PADD is found below in Table VI-A.3-1. 51 EIA Monthly Energy Review, June 2006 (Table 10.1: Renewable Energy Consumption by Source, Appendix A: Thermal Conversion Factors). 52 File containing historical RFG MTBE usage obtained from EIA representative on March 9, 2006. 53 EIA 2004 Petroleum Marketing Annually (Table 48: Prime Supplier Sales Volumes of Motor Gasoline by Grade, Formulation, PAD District, and State). Table VI.A.3-1.—2004 U.S. Gasoline & Oxygenate Consumption by PADD PADD Gasoline MMgal Ethanol MMgal Percent of gasoline MTBE a MMgal Percent of gasoline PADD 1 49,193 660 1.3 1,360 2.8 PADD 2 38,789 1,616 4.2 1 0.0 PADD 3 20,615 79 0.4 498 2.4 PADD 4 4,542 83 1.8 0 0.0 PADD 5 b 7,918 209 2.6 19 0.2 California 14,836 853 5.8 0 0.0 Total 135,893 3,500 2.6 1,878 1.4 a MTBE blended into RFG. b PADD 5 excluding California. As shown above, nearly half (or about 45 percent) of the ethanol was consumed in PADD 2 gasoline, where the majority of ethanol was produced. The next highest region of use was the State of California which accounted for about 25 percent of domestic ethanol consumption. This is reasonable because California alone accounts for over 10 percent of the nation's total gasoline consumption and all the fuel (both Federal RFG and California Phase 3 RFG) has been assumed to contain ethanol (following their recent MTBE ban) at 5.7 volume percent. 54 The bulk of the remaining ethanol was used in reformulated gasoline
(RFG)and winter oxy-fuel areas requiring oxygenated gasoline. Overall, 62 percent of ethanol was used in RFG, 33 percent was used in CG, and 5 percent was used in winter oxy-fuel. 55 54 Current California gasoline regualtions make it very difficult to meet the NO <sup>X</sup> emissions performance standard with ethanol content higher than about 6 vol%. For our analysis, all California RFG was assumed to contain 5.7 volume percent ethanol based on a conversation with Dean Simeroth at California Air Resources Board (CARB). 55 For the purpose of this analysis, except where noted, the term “RFG” pertains to Federal RFG plus California Phase 3 RFG (CaRFG3) and Arizona Clean Burning Gasoline (CBG). As shown above in Table VI.A.3-1, 99 percent of MTBE use occurred in PADDs 1 and 3. This reflects the high concentration of RFG areas in the northeast (PADD 1) and the local production of MTBE in the gulf coast (PADD 3). PADD 1 receives a large portion of its gasoline from PADD 3 refineries who either produce the fossil-fuel based oxygenate or are closely affiliated with MTBE-producing petrochemical facilities in the area. Overall, 100 percent of MTBE in 2004 was assumed to be used in reformulated gasoline. 56 56 2004 MTBE consumption was obtained from EIA. The data received was limited to states with RFG programs, thus MTBE use was assumed to be limited to RFG areas for the purpose of this analysis. In 2004, total ethanol use exceeded MTBE use. Ethanol's lead oxygenate role is relatively new, however the trend has been a progression over the past few years. From 2001 to 2004, ethanol consumption more than doubled (from 1.7 to 3.5 billion gallons), while MTBE use (in RFG) was virtually cut in half (from 3.7 to 1.9 billion gallons). A plot of oxygenate use over the past decade is provided below in Figure VI.A.3-1. The nation's transition to ethanol is linked to states' responses to recent environmental concerns surrounding MTBE groundwater contamination. Resulting concerns over drinking water quality have prompted several states to significantly restrict or completely ban MTBE use in gasoline. At the time of this analysis, 19 states had adopted MTBE bans. A list of the states with MTBE bans is provided in RIA Table 2.1-4. ER01MY07.049 4. Expected Growth in Ethanol Consumption As mentioned above, ethanol demand is expected to increase well beyond the levels contained in the renewable fuels standard
(RFS)under the Act. With the removal of the RFG oxygenate mandate, 57 all U.S. refiners are taking steps to eliminate the use of MTBE as quickly as possible. In order to complete this transition quickly (by 2007 at the latest) while maintaining gasoline volume, octane, and mobile source air toxics emission performance standards, refiners have elected to blend ethanol into virtually all of their RFG. 58 This has caused a dramatic increase in demand for ethanol which, in 2006, was met by temporarily shifting large volumes of ethanol out of conventional gasoline and into RFG areas. By 2012, however, ethanol production will have grown to accommodate the removal of MTBE without the need for such a shift from conventional gasoline. More important than the removal of MTBE over the long term, however, is the impact that the rise in crude oil price is having on demand for renewable fuels, both ethanol and biodiesel. This has dramatically improved the economics for renewable fuel use, leading to a surge in demand that is expected to continue. In the Annual Energy Outlook
(AEO)2006, EIA forecasted that by 2012, total ethanol use (corn, cellulosic, and imports) would be about 9.6 billion gallons and biodiesel use would be about 0.3 billion gallons at a crude oil price forecast of $48 per barrel. 59 This ethanol projection was not based on what amount the market would demand (which could be higher), but rather on the amount that could be produced by 2012. Others are making similar predictions, and as discussed above in VI.A.2, production capacity would be sufficient. 57 Energy Act Section 1504, promulgated on May 8, 2006 at 71 FR 26691. 58 Based on discussions with the refining industry. 59 In AEO 2007, EIA is forecasted an even higher ethanol consumption of 11.2 billion gallons by 2012. The draft report was issued on December 5, 2006 and we could not incorporate it into the refinery modeling used to conduct our analyses. In assessing the impacts of expanded renewable fuel use, we have chosen to evaluate two different future ethanol consumption levels, one reflecting the statutory required minimum, and one reflecting the higher levels projected by EIA. For the statutory consumption scenario we assumed 6.7 billion gallons of ethanol use (0.25 billion gallons of which was assumed to be cellulosic) and 0.3 billion gallons of biodiesel. This figure is lower than the 7.2 billion gallons of ethanol we modeled in the proposal because it considers the renewable fuel equivalence values we are finalizing for corn ethanol (1), biodiesel (1.5) and cellulosic ethanol (2.5). For the higher projected renewable fuel consumption scenario, we assumed 9.6 billion gallons of ethanol (0.25 billion gallons of which was assumed to be cellulosic) and 0.3 billion gallons of biodiesel. Although the actual renewable fuel volumes consumed in 2012 may differ from both the required and projected volumes, we believe that these two scenarios provide a reasonable range for analysis purposes. For more information on how the renewable fuel usage scenarios we considered, refer to RIA Section 2.1. To estimate where ethanol would be consumed in 2012, we used a linear programming
(LP)refinery cost model (discussed in more detail in Section VII). For both future ethanol consumption scenarios discussed above, the modeling provided us with a summary of ethanol usage by PADD, fuel type, and season. There was some post-processing involved to ensure that all state ethanol mandates and winter oxy-fuel requirements were satisfied. The adjusted results for the 6.7 Bgal RFS case and the 9.6 Bgal EIA case are presented below in Tables VI.A.4-1 and VI.A.4-2, respectively. Table VI.A.4-1.—Forecasted 2012 U.S. Ethanol Consumption (MMgal) 6.7 Bgal RFS Case PADD Summer ethanol use CG a RFG b Total Winter ethanol use CG a RFG b Total Total ethanol PADD 1 399 679 1,078 350 706 1,057 2,134 PADD 2 1,667 59 1,726 1,082 288 1,370 3,096 PADD 3 161 47 208 146 0 146 354 PADDs 4/5 c 135 0 135 138 0 138 274 California 0 414 414 0 398 398 813 Total 2,362 1,200 3,562 1,717 1,392 3,109 6,671 a Includes Arizona CBG and winter oxy-fuel. b Federal RFG and California Phase 3 RFG. c PADDS 4 and 5 excluding California. Table VI.A.4-1.—Forecasted 2012 U.S. Ethanol Consumption by Season (MMgal) 9.6 Bgal EIA Case PADD Summer ethanol use CG a RFG b Total Winter ethanol use CG a RFG b Total Total ethanol PADD1 610 630 1,240 267 973 1,240 2,481 PADD2 1,735 185 1,919 1,631 366 1,998 3,917 PADD3 901 47 949 856 0 856 1,805 PADD 4/5 c 339 0 339 154 0 154 492 California 0 435 435 0 470 470 905 Total 3,584 1,298 4,882 2,908 1,809 4,718 9,600 a Includes Arizona CBG and winter oxy-fuel. b Federal RFG and California Phase 3 RFG. c PADDs 4 and 5 excluding California. As shown above, the LP modeling predicts that the majority of ethanol will be consumed in PADD 2, where most of the ethanol is produced. The results show varying levels of ethanol usage in RFG in response to the removal of the oxygenate requirement. For the higher ethanol consumption scenario, the modeling suggests that the majority of additional ethanol would be absorbed in PADD 3 conventional gasoline. With respect to seasonality, in both cases, the modeling predicts that a greater fraction of ethanol use would occur in the summertime due to the 1psi RVP waiver. For a more detailed discussion on future ethanol consumption, refer to Chapter 2 of the RIA. B. Overview of Biodiesel Industry and Future Production/Consumption 1. Characterization of U.S. Biodiesel Production/Consumption Historically, the cost to make biodiesel was an inhibiting factor to production in the U.S. The cost to produce biodiesel was high compared to the price of petroleum derived diesel fuel, even with the subsidies and credits provided by federal and state programs. Much of the demand occurred as a result of mandates from states and local municipalities, that required the use of biodiesel. However, over the past couple of years biodiesel production has been increasing rapidly. The combination of higher crude oil prices and greater federal tax subsidies has created a favorable economic situation. The Biodiesel Blenders Tax Credit programs and the Commodity Credit Commission Bio-energy Program, both subsidize producers and offset production costs. The Energy Policy Act extended the Biodiesel Blenders Tax Credit program to 2008. This credit provides about one dollar per gallon in the form of a federal excise tax credit to biodiesel blenders from virgin vegetable oil feedstocks and 50 cents per gallon to biodiesel produced from recycled grease and animal fats. The program was started in 2004 under the American Jobs Act, spurring the expansion of biodiesel production and demand. Historical estimates and future forecasts of biodiesel production in the U.S. are presented in Table VI.B.1-1 below. Table VI.B.1-1.—Estimated Biodiesel Production Year Million gallons per year 2001 5 2002 15 2003 20 2004 25 2005 91 2006 150 2007 414 2012 303 Source: Historical data from 2001-2004 obtained from estimates from John Baize “ The Outlook and Impact of Biodiesel on the Oilseeds Sector” USDA Outlook Conference 06. Year 2005 data from USDA Bioenergy Program *http://www.fsa.usda.gov/daco/bioenergy/2005/FY2005ProductPayments,* Year 2006 data from verbal quote based on projection by NBB in June of 2006. Production data for years 2007 and higher are from EIA's AEO 2006. With the increase in biodiesel production, there has also been a corresponding rapid expansion in biodiesel production capacity. Presently, there are 85 biodiesel plants in operation with an annual production capacity of 580 million gallons per year. 60 The majority of the current production capacity was built in 2005 and 2006, and was first available to produce fuel in the later part of 2005 and in 2006. Though the capacity has grown, historically the biodiesel production capacity has far exceeded actual production with only 10-30 percent of this being utilized to make biodiesel. The excess capacity, though, may be from biodiesel plants that do not operate full time and from production capacity that is primarily devoted to making esters for the ole-chemical markets, see Table VI.B.1-2. 60 NBB Survey September 13, 2006 “U.S. Biodiesel Production Capacity”. 61 From Presentation “Biodiesel Production Capacity,” by Leland Tong, National Biodiesel Conference and Expo, February 7, 2006. Table VI.B.1-2.—U.S. Production Capacity History a 2001 2002 2003 2004 2005 2006 Plants 9 11 16 22 45 85 Capacity (million gal/yr) 50 54 85 157 290 580 a Capacity Data based on surveys conducted around the month of September for most years, though the 2006 information is based on a survey conducted in January 2006. 61 2. Expected Growth in U.S. Biodiesel Production/Consumption In addition to the 85 biodiesel plants already in production, as of early 2006, there were 65 plants in the construction phase and 13 existing plants that are expanding their capacity, which when completed would increase total biodiesel production capacity to over one billion gallons per year. Most of these plants should be completed by late 2007. As shown in Table VI.B.2-1 if all of this capacity came to fruition, U.S. biodiesel capacity would exceed 1.4 billion gallons. Table VI.B.2-1.—Projected Biodiesel Production Capacity Existing plants Construction phase Number of plants 85 78 Total Plant Capacity, (MM Gallon/year) 580 1,400 For cost and emission analysis purposes, three biodiesel usage cases were considered: A 2004 base case, a 2012 reference case, and a 2012 control case. The 2004 base case was formed based on historical biodiesel usage (25 million gallons as summarized in Table VI.B.1.1). The reference case was computed by taking the 2004 base case and growing it out to 2012 by applying the 2004-2012 EIA diesel fuel growth rate. 62 The resulting 2012 reference case consisted of 30 million gallons of biodiesel. Finally, for the 2012 control case, forecasted biodiesel use was assumed to be 300 million gallons based on EIA's AEO 2006 report (rounded value from Table VI.B.1.1). Unlike forecasted ethanol use, biodiesel use was assumed to be constant at 300 million gallons under both the statutory and higher projected renewable fuel consumption scenarios described in VI.A.4. EIA's projection is based on the assumption that the blender's tax credit is not renewed beyond 2008. If the tax credit is renewed, the projection for biodiesel demand would increase. 62 EIA Annual Energy Outlook 2006, Table 1. C. Feasibility of the RFS Program Volume Obligations This section examines whether there are any feasibility issues associated with the meeting the minimum renewable fuel requirements of the Energy Act. Issues are examined with respect to renewable production capacity, cellulosic ethanol production capacity, and distribution system capability. Land resource requirements are discussed in Chapter 7 of the RIA. 1. Production Capacity of Ethanol and Biodiesel As shown in Sections VI.A. and VI.B., increases in renewable fuel production capacity are already proceeding at a pace significantly faster than required to meet the 2012 mandate in the Act of 7.5 billion gallons as well as the mandate (starting in 2013) of a minimum of 250 million gallons of cellulosic ethanol. The combination of ethanol and biodiesel plants in existence and planned or under construction is expected to provide a total renewable fuel production capacity of over 9.6 billion gallons by the end of 2012. Production capacity is expected to continue to increase in response to strong demand. We estimate that this will require a maximum of 2,100 construction workers and 90 engineers on a monthly basis through 2012. 2. Technology Available To Produce Cellulosic Ethanol There are a wide variety of government and renewable fuels industry research and development programs dedicated to improving our ability to produce renewable fuels from cellulosic feedstocks. In this discussion, we deal with at least three completely different approaches to producing ethanol from cellulosic biomass. The first is based on what NREL refers to as the “sugar platform,” 63 which refers to pretreating the biomass, then hydrolyzing the cellulosic and hemicellulosic components into sugars, and then fermenting the sugars into ethanol. 63 Enzyme Sugar Platform (ESP), Project Next Steps National Renewable Energy, Dan Schell, FY03 Review Meeting; Laboratory Operated for the U.S. Department of Energy by Midwest Research Institute • B NREL, Golden, Colorado, May 1-2, 2003; U.S. Department of Energy by Midwest Research Institute • Battelle • Bechtel. Corn grain is a nearly ideal feedstock for producing ethanol by fermentation, especially when compared with cellulosic biomass feedstocks. Corn grain is easily ground into small particles, following which the exposed starch which has α-linked saccharide polymers is easily hydrolyzed into simple, single component sugar which can then be easily fermented into ethanol. By comparison, the biomass lignin structure must be either mechanically or chemically broken down to permit hydrolyzing chemicals and enzymes access to the saccharide polymers. The central problem is that the cellulose/hemicellulose saccharide polymers are β-linked which makes hydrolysis much more difficult. Simple microbial fermentation used in corn sugar fermentation is also not possible, since the cellulose and hemicellulose (6 & 5 carbon molecules, respectively) have not been able to be fermented by the same microbe. We discuss various pretreatment, hydrolysis and fermentation technologies, below. The second and third approaches have nothing to do with pretreatment, acids, enzymes, or fermentation. The second is sometimes referred to as the “syngas” or “gas-to-liquid” approach; we will call it the “Syngas Platform.” Briefly, the cellulosic biomass feedstock is steam-reformed to produce syngas which is then converted to ethanol over a Fischer-Tropsch catalyst. The third approach uses plasma technology. a. Sugar Platform Plant cell walls are made up of cellulose and hemicellulose polymers embedded in a lignin matrix. This complex structure prevents both the first step, hydrolyzation of the cellulose and hemicellulose polymers, and the second step, fermentation of the hydrolyzed sugars into ethanol. i. Pretreatment Those who wish to use cellulosic biomass feedstocks to produce ethanol face several, difficult problems. The lignin sheath, present in all cellulosic materials, prevents, or at the very least, severely restricts hydrolysis. To produce ethanol from cellulosic biomass feedstocks by fermentation, some type of thermo-mechanical, mechanical, chemical or a combination of these pretreatments is always necessary before the cellulosic and hemicellulosic polymers can be hydrolyzed. In effect, the lignin structure must be “opened” to allow efficient and effective strong acid hydrolysis, weak acid hydrolysis, or weak acid enzymatic hydrolysis of the cellulose/hemicellulose to their glucose and xylose sugar components. Over time, many pretreatment methods or combinations of methods have been tried, some with more success than others. Usually, intense physical pretreatments such as steam explosion are required; grasses and forest thinnings usually need to be chipped, prior to chemical or enzymatic hydrolysis. The most common chemical pretreatments for cellulosic feedstocks are strong acid, dilute acid, caustic, organic solvents, ammonia, sulfur dioxide, carbon dioxide or other chemicals which make the biomass more accessible to the enzymes. Following pretreatment, acidic (dilute and concentrated) and enzymatic hydrolysis are the two process types commonly used to hydrolyze cellulosic feedstocks before fermentation into ethanol. 64 64 Appendix B, Overview of Cellulose-Ethanol Production Technology; OREGON CELLULOSE-ETHANOL STUDY, *An evaluation of the potential for ethanol production in Oregon using cellulose-based feedstocks* ; Prepared by: Angela Graf, Bryan & Bryan Inc., 5015 Red Gulch, Cotopaxi, Colorado 81223; Tom Koehler, Celilo Group, 2208 S.W. First Ave, #320, Portland, Oregon 97204; For submission to: The Oregon Office of Energy. ii. Dilute Acid Hydrolysis Dilute acid hydrolysis is the oldest technology for converting cellulose biomass to ethanol. The dilute acid process uses a 1-percent sulfuric acid in a continuous flow reactor at about 420 °F; reaction times are measured in seconds and minutes, which facilitates continuous processing. The process involves two reactions with a sugar conversion efficiency of about 50 percent. The process conditions at which the cellulosic molecules are converted into sugar are also those at which the sugar is almost immediately converted into other chemicals, principally furfural. The rapid conversion to furfural reduces the sugar yield, which along with other by-products inhibits the fermentation process. One way to decrease sugar degradation is to use a two-stage process which takes advantage of the fact that hemicellulose (5-carbon) sugars degrade more rapidly than cellulose (6-carbon) sugars. The first stage is conducted under mild process conditions to recover the 5-carbon sugars, while the second stage is conducted under harsher conditions to recover the 6-carbon sugars. Both hydrolyzed solutions are then fermented to ethanol. Lime is used to neutralize the residual acid before the fermentation stage. Regardless, some sugar degrades to furfural, which naturally limits the net yield of ethanol. The residual cellulose and lignin are used as boiler fuel for electricity or steam production. 65 65 Ibid. iii. Concentrated acid hydrolysis Concentrated acid hydrolysis uses a 70-percent sulfuric acid solution, followed by water hydrolysis to convert the cellulose into sugar. The process rapidly, and nearly completely, converts cellulose to glucose (6-carbon) and hemicellulose to xylose (5-carbon) sugar, with little degradation to furfural; the reaction times are typically slower than those of the dilute acid process. The critical factors needed to make this process economically viable are to optimize sugar recovery and cost effectively recover the acid for recycling. The concentrated acid process is somewhat more complicated and requires more time, but it has the primary advantage of yielding up to about 90% of both hemicellulosic and cellulosic sugars. 66 In addition, a significant advantage of the concentrated acid process is that it is carried out at relatively low temperatures, about 212 °F, and low pressure, such that fiberglass reactors and piping can be used. 66 Ibid. iv. Enzymatic hydrolysis Enzymatic hydrolysis is not necessarily a recent discovery. We found reports of research conducted by a variety of companies and government agencies going back to at least 1991. 67 68 69 The enzymatic hydrolysis of cellulose was reportedly discovered when a fungus, *trichoderma reesei* , was identified which produced cellulase enzymes that broke down cotton clothing and tents in the South Pacific during World War II. Since then, generations of cellulases have been developed through genetic modifications of the fungus strain. As in acid hydrolysis, the hydrolyzing enzymes must have access to the cellulose and hemicellulose in order to work efficiently. Although enzymatic hydrolysis requires some kind of pretreatment, purely physical pretreatments are typically not adequate. Furthermore, the chemical method uses dilute sulfuric acid, which is poisonous to the fermentation microorganisms and must be detoxified. While original enzymatic hydrolysis processes used separate hydrolysis and fermentation steps, recent process improvements integrate saccharification and fermentation by combining the cellulase enzymes and fermenting microbes in one vessel. This results in a one-step process of sugar production and fermentation, referred to as the simultaneous saccharification and fermentation
(SSF)process. One disadvantage is that the cellulase enzyme and fermentation organism must operate under the same process conditions, which could decrease the sugar and, ultimately, the ethanol yields. An alternative to the SSF technology is the sequential hydrolysis and fermentation
(SHF)process. The separation of hydrolysis and fermentation enables enzymes to operate at higher temperatures in the hydrolysis step to increase sugar production and more moderate temperatures in the fermentation step to optimize the conversion of sugar into ethanol. 67 Technical and Economic Analysis Of An Enzymatic Hydrolysis Based Ethanol Plant, Fuels and Chemicals Research and Engineering Division, Solar Energy Research Institute, Golden CO, 80401, June 1991 • DRAFT • SERI Protected Proprietary Information • Do Not Copy. 68 Biomass to Ethanol Process Evaluation, A report prepared for National Renewable Energy Laboratory, December 1994; Chem Systems Inc. 303 South Broadway, Tarrytown, New York, 10591. 69 Lignocellulosic Biomass to Ethanol Process Design and Economics Utilizing Co-Current Dilute Acid Prehydrolysis and Enzymatic Hydrolysis Current and Futuristic Scenarios, July 1999 • NREL/TP-580-26157; Robert Wooley, Mark Ruth, John Sheehan, and Kelly Ibsen, Biotechnology Center for Fuels and Chemicals; Henry Majdeski and Adrian Galvez, Delta-T Corporation; National Renewable Energy Laboratory, 1617 Cole Boulevard, Golden, Colorado 80401-3393; NREL is a U.S. Department of Energy Laboratory Operated by Midwest Research Institute • Battelle • Bechtel; Contract No. DE-AC36-98-GO10337. Cost-effective cellulase enzymes must also be developed for this technology to be completely successful. 70 Several companies are using variations of these technologies to develop processes for converting cellulosic biomass into ethanol by way of fermentation. A few groups, using recently developed genome modifying technology, have been able to produce a variety of new or modified enzymes and microbes that show promise for use in weak- or dilute-acid enzymatic-prehydrolysis. Another problem with cellulosic feedstocks is, as previously described, that the hydrolysis reactions produce both glucose, the six-carbon sugar, and xylose, the five-carbon sugar (pentose sugar, C <sup>5</sup> H <sup>10</sup> O <sup>5</sup> ; sometimes called “wood sugar”). Early conversion technology required different microbes to ferment each sugar. Recent research has developed better fermenting organisms. Now, glucose and xylose can be co-fermented—hence, the present-day terminology: Weak-acid enzymatic hydrolysis and co-fermentation. 70 Ibid. b. Syngas Platform The second platform for producing cellulosic ethanol is to convert the biomass into a syngas which is then converted into ethanol. A “generic” syngas process is essentially a “steam reformer,” which “gasifies” biomass and other carbon based substances including wastes, in a reduced-oxygen environment and reacts them with steam to produce a synthesis gas or “syngas” consisting primarily of carbon monoxide and hydrogen. The syngas is then passed over in a Fischer-Tropsch catalyst to produce ethanol. The biomass feedstock is dried to about 15% moisture content and ground small enough to be efficiently burned and reacted in the reformer. The reformer, an important upstream element of the process, is essentially a common solid-fuel gasifier, which with some modification and steam injection becomes what is sometimes referred to as the “primary reformer.” When any fuel is completely burned, all of its potential energy is released as heat which can be recovered for immediate use. In a common gasification process, the partially burned fuel (wood or coal) releases a small amount of heat, but leaves some uncombusted, gaseous products. Ordinarily, the hot product gases are fed directly to a nearby boiler or gas turbine, to do work; it has been reported that for a well-designed system, the overall efficiency may approach that of a solid fuel boiler. However, when steam is injected into the gasifier, it reacts with the burning solid fuel to produce more gaseous product. The primary reaction is between carbon and water which produces hydrogen and carbon monoxide and an inorganic ash. The ash and heavy hydrocarbon-tars are removed from the raw syngas before it is compressed and passed over Fisher-Tropsch catalyst to produce ethanol. Fisher-Tropsch technology has been used for many years in the chemical and refining industries, most notably to produce gasoline and diesel fuel from syngas produced by coal gasification. Whether the Fischer-Tropsch reaction produces diesel or ethanol is primarily the result of changes to process pressure, temperature and in some cases the use of custom catalysts. In most cases, the Fischer-Tropsch process did not produce pure ethanol in the first pass through the system. Rather, a stream of mixed chemicals was produced, including gasoline, diesel, and oxygenated hydrocarbons (alcohol). 71 71 Gridley Ethanol Demonstration Project Utilizing Biomass Gasification Technology: Pilot Plant Gasifier and Syngas Conversion Testing, August 2002-June 2004; February 2005 • NREL/SR-510-37581; TSS Consultants, For the City of Gridley, California, 1617 Cole Boulevard, Golden, Colorado 80401-3393, 303-275-3000 • *http://www.nrel.gov* ; Operated for the U.S. Department of Energy Office of Energy Efficiency and Renewable Energy by Midwest Research Institute • Battelle Contract No. DE-AC36-99-GO10337. c. Plasma Technology The development of another technology, called plasma, is also underway for creating a syngas from which ethanol is produced. A plasma “reactor,” generates an ionized gas (plasma) which serves as an electrical conductor to transfer intense radiant energy to a biomass or waste material. This intense energy is said to actually breakdown the various materials in the biomass or waste into their atomic components. Anything present in the feed-mass that doesn't gasify, is essentially “vitrified.” This vitrified stream is reportedly inert and can be used as aggregate in paving materials. Following gasification, the syngas is cooled, impurities are removed, and the gas is sent to ethanol production as with the syngas platform described above. 72 72 Ethanol From Tires Via Plasma Converter Plus Fischer Tropsch, March 15, 2006; *http://thefraserdomain.typepad.com/energy/2006/03/ethanol_from_ti.html* . d. Feedstock Optimization Cellulosic biomass can come from a variety of sources. Because the conversion of cellulosic biomass to ethanol has not yet been commercially demonstrated, we cannot say at this time which feedstocks are superior to others. A few of the many resources are: Post-sorted municipal waste, rice and wheat straw, 73 soft-woods, hardwood, switch grass, and bagasse. Regardless, each feedstock requires a specific combination of pretreatment methods and enzyme “cocktails” to optimize the operation and maximize the ethanol yield. One of the many challenges for the cellulose-ethanol industry is to find the best feedstocks and then develop the most cost-effective ways for converting them into ethanol. 73 Wheat Straw for Ethanol Production in Washington: A Resource, Technical, and Economic Assessment, September 2001, WSUCEEP2001084; Prepared by: James D. Kerstetter, Ph.D., John Kim Lyons, Washington State University Cooperative Extension Energy Program, 925 Plum Street, SE., P.O. Box 43165, Olympia, WA 98504-3165; Prepared for: Washington State Office of Trade and Economic Development. 3. Renewable Fuel Distribution System Capability Ethanol and biodiesel blended fuels are currently not shipped by petroleum product pipeline due to operational issues and additional cost factors. Hence, a separate distribution system is needed for ethanol and biodiesel up to the point where they are blended into petroleum-based fuel as it is loaded into tank trucks for delivery to retail and fleet operators. In cases where ethanol and biodiesel are produced within 200 miles of a terminal, trucking is often the preferred means of distribution. For longer shipping distances, the preferred method of bringing renewable fuels to terminals is by rail and barge. Modifications to the rail, barge, tank truck, and terminal distribution systems will be needed to support the transport of the anticipated increased volumes of renewable fuels. These modifications include the addition of terminal blending systems for ethanol and biodiesel, additional storage tanks at terminals, additional rail delivery systems at terminals for ethanol and biodiesel, and additional rail cars, barges, and tank trucks to distribute ethanol and biodiesel to terminals. Terminal storage tanks for 100 percent biodiesel will also need to be heated during cold months to prevent gelling. The most comprehensive study of the infrastructure requirements for an expanded fuel ethanol industry was conducted for the Department of Energy
(DOE)in 2002. 74 The conclusions reached in that study indicate that the changes needed to handle the anticipated increased volume of ethanol by 2012 will not represent a major obstacle to industry. While some changes have taken place since this report was issued, including an increased reliance on rail over marine transport, we continue to believe that the rail and marine transportation industries can manage the increased growth in demand in an orderly fashion. This belief is supported by the demonstrated ability for the industry to handle the rapid increases and redistribution of ethanol use across the country over the last several years as MTBE was removed. The necessary facility changes at terminals and at retail stations to dispense ethanol containing fuels have been occurring at a record pace. Given that future growth is expected to progress at a steadier pace and with greater advance warning in response to economic drivers, we anticipate that the distribution system will be able to respond appropriately. A discussion of the costs associated making the changes discussed above is contained in Section VII.B of today's preamble. 74 “Infrastructure Requirements for an Expanded Fuel Ethanol Industry,” Downstream Alternatives Inc., January 15, 2002. VII. Impacts on Cost of Renewable Fuels and Gasoline This section examines the impact on fuel costs resulting from the growth in renewable fuel use between a base year of 2004 and 2012. We note that based on analyses conducted by the Energy Information Administration (EIA), renewable fuels will be used in gasoline and diesel fuel in excess of the RFS requirements. As such, the changes in the use of renewable fuels and their related cost impacts are not directly attributable to the RFS rule. Rather, our analysis assesses the broader fuels impacts of the growth in renewable fuel use in the context of corresponding changes to the makeup of gasoline. These fuel impacts include the elimination of the reformulated gasoline
(RFG)oxygen standard which has resulted in the refiners ceasing to use the gasoline blendstock methyl tertiary butyl ether
(MTBE)and replacing it with ethanol. Thus, in this analysis, we are assessing the impact on the cost of gasoline and diesel fuel of increased use of renewable fuels, the cost savings resulting from the phase out of MTBE and the increased cost due to the other changes in fuel quality that result. As discussed in Section II, we chose to analyze a range of renewable fuel use. In the case of ethanol's use in gasoline, the lower end of this range is based on the minimum renewable fuel volume requirements in the Act, (the RFS case) and the higher end is based on AEO 2006 (the EIA case). At both ends of this range, we assume that biodiesel consumption will be the level estimated in AEO 2006. We analyzed the projected fuel consumption scenario and associated program costs in 2012, the year that the RFS is fully phased-in. The volumes of renewable fuels consumed in 2012 at the two ends of the range are summarized in Table II.A.1-1. We have estimated an average corn ethanol production cost of $1.26 per gallon in 2012 (2004 dollars) for the RFS case and $1.32 per gallon for the EIA case. For cellulosic ethanol, we estimate it will cost approximately $1.65 in 2012 (2004 dollars) to produce a gallon of ethanol using corn stover as a cellulosic feedstock. In this analysis, however, we assume that the cellulosic requirement will be met by corn-based ethanol produced by energy sourced from biomass (animal and other waste materials as discussed in Section III.B of today's preamble) and costing the same as corn based ethanol produced by conventional means. We estimated production costs for soy-derived biodiesel of $2.06 per gallon in 2004 and $1.89 per gallon in 2012. For yellow grease derived biodiesel, we estimate an average production cost of $1.19 per gallon in 2004 and $1.11 in 2012. For the proposed rule, we estimated the cost of increased use of renewable fuel and other major cost impacts by developing our own cost spreadsheet model. That analysis considered the production cost, distribution cost as well as the cost for balancing the octane and RVP caused by these fuel changes. That analysis, however, could not properly balance octane and other gasoline qualities. For this final rule, we have therefore used the services of Jacobs Consultancy to run their refinery LP model to estimate the cost impacts of the RFS rule. The results from the refinery LP model indicate that the impacts on overall gasoline costs from the increased use of ethanol and the corresponding changes to the other aspects of gasoline would be 0.49 cents per gallon for the RFS case. The EIA case would result in increased total cost of 1.03 cents per gallon. The actual cost at the fuel pump, however, will be decreased due to the effect of State and Federal tax subsidies for ethanol. Taking this into consideration results in “at the pump” decreased costs (cost savings) of −0.47 cents per gallon for the RFS case and “at the pump” decreased cost of −0.83 cents per gallon for the EIA case. Section 7 of the RIA contains more detail on the cost analysis used to develop these costs. A. Renewable Fuel Production and Blending Costs 1. Ethanol Production Costs a. Corn Ethanol A significant amount of work has been done in the last decade on surveying and modeling the costs involved in producing ethanol from corn to serve business and investment purposes as well as to try to educate energy policy decisions. Corn ethanol costs for our work were estimated using a model developed by USDA in the 1990s that has been continuously updated by USDA. The most current version was documented in a peer-reviewed journal paper on cost modeling of the dry-grind corn ethanol process, and it produces results that compare well with cost information found in surveys of existing plants. 75 76 We made some minor modifications to the USDA model to allow scaling of the plant size, to allow consideration of plant energy sources other than natural gas, and to adjust for energy prices in 2012, the year of our analysis. 75 Kwaitkowski, J.R., McAloon, A., Taylor, F., Johnston, D.B., Industrial Crops and Products 23
(2006)288-296. 76 Shapouri, H., Gallagher, P., USDA's 2002 Ethanol Cost-of-Production Survey (published July 2005). The cost of ethanol production is most sensitive to the prices of corn and the primary co-product, DDGS. Utilities, capital, and labor expenses also have an impact, although to a lesser extent. Corn feedstock minus DDGS sale credits represents about 48% of the final per-gallon cost, while utilities, capital and labor comprise about 19%, 9%, and 6%, respectively. For this work, we used corn prices of $2.50/bu and $2.71/bu for the RFS and EIA cases, respectively, with corresponding DDGS prices at $83.35/ton and $85.16/ton (2004 dollars). These estimates are from modeling work done for this rulemaking using the Forestry and Agricultural Sector Optimization Model, which is described in more detail in Chapter 8 of the RIA. Energy prices were derived from historical data and projected to 2012 using EIA's AEO 2006. More details on how the ethanol production cost estimates were made can be found in Chapter 7 of the RIA. The estimated average corn ethanol production cost of $1.26 per gallon in 2012 (2004 dollars) in the RFS case and $1.32 per gallon in the EIA case represents the full cost to the plant operator, including purchase of feedstocks, energy required for operations, capital depreciation, labor, overhead, and denaturant, minus revenue from sale of co-products. It assumes that 86% of new plants will use natural gas as a thermal energy source, at a price of $6.16/MMBtu (2004 dollars). 77 It does not account for any subsidies on production or sale of ethanol. Note that the cost figure generated here is independent of the market price of ethanol, which has been related closely to the wholesale price of gasoline for the past decade. 78 79 77 For more details on fuel sources and costs of production, see RIA Chapter 1.2.2 and 7.1.1.2. 78 Whims, J., Sparks Companies, Inc. and Kansas State University, “Corn Based Ethanol Costs and Margins, Attachment 1” (Published May 2002). 79 Piel, W.J., Tier & Associates, Inc., March 9, 2006 report on costs of ethanol production and alternatives. Under the Energy Act, starch-based ethanol can be counted as cellulosic if at least 90% of the process energy is derived from renewable feedstocks, which include plant cellulose, municipal solid waste, and manure biogas. 80 It is expected that the vast majority of the 250 million gallons per year of cellulosic ethanol production required by 2013 will be made using this provision. While we have been unable to develop a detailed production cost estimate for corn ethanol meeting cellulosic criteria, we assume that the costs will not be significantly different from conventionally produced corn ethanol. We believe this is reasonable because the costs of hauling, storing, and processing this low or zero cost waste material in order to combust it will be significant, thus making overall production costs at these plants similar to gas-fired ethanol plants. As of the time of this writing, we know of only a few operating plants of this type, and expect the quantity of ethanol produced this way to remain a relatively small fraction of the total ethanol demand. Thus, the sensitivity of the overall analysis to this assumption is also very small. 81 Based on these factors, we have assigned starch ethanol made using this cellulosic criteria the same cost as ethanol produced from corn using conventional means. 80 Energy Policy Act of 2005, Section 1501 amending Clean Air Act Section 211(o)(1)(A). 81 See Table VI.A.1-2 for more details on number of operating ethanol plants and their fuel sources. b. Cellulosic Ethanol In 1999, the National Renewable Energy Laboratory
(NREL)published a report outlining its work with the USDA to design a computer model of a plant to produce ethanol from hard-wood chips. 82 Although the model was originally prepared for hardwood chips, it was meant to serve as a modifiable-platform for ongoing research using cellulosic biomass as feedstock to produce ethanol. Their long-term plan was that various indices, costs, technologies, and other factors would be regularly updated. 82 Lignocellulosic Biomass to Ethanol Process Design and Economics Utilizing Co-Current Dilute Acid Prehydrolysis and Enzymatic Hydrolysis Current and Futuristic Scenarios, Robert Wooley, Mark Ruth, John Sheehan, and Kelly Ibsen, Biotechnology Center for Fuels and Chemicals, Henry Majdeski and Adrian Galvez, Delta-T Corporation; National Renewable Energy Laboratory, Golden, CO, July 1999, NREL/TP-580-26157. NREL and USDA used a modified version of the model to compare the cost of using corn-grain with the cost of using corn stover to produce ethanol. We used the corn stover model from the second NREL/USDA study for the analysis for this rule. Because there were no operating plants that could potentially provide real world process design, construction, and operating data for processing cellulosic ethanol, NREL had considered modeling the plant based on assumptions associated with a first-of-a-kind or pioneer plant. The literature indicates that such models often underestimate actual costs since the high performance assumed for pioneer process plants is generally unrealistic. Instead, the NREL researchers assumed that the corn stover plant was an Nth generation plant, e.g., not a pioneer plant or first-or-its kind, built after the industry had been sufficiently established to provide verified costs. The corn stover plant was normalized to the corn kernel plant, e.g., placed on a similar basis. 83 It is also reasonable to expect that the cost of cellulosic ethanol would be higher than corn ethanol because of the complexity of the cellulose conversion process. Recently, process improvements and advancements in corn production have considerably reduced the cost of producing corn ethanol. We also believe it is realistic to assume that cellulose-derived ethanol process improvements will be made and that one can likewise reasonably expect that, as the industry matures, the cost of producing ethanol from cellulose will also decrease. 83 Determining the Cost of Producing Ethanol from Corn Starch and Lignocellulosic Feedstocks; A Joint Study Sponsored by: USDA and USDOE, October 2000 • NREL/TP-580-28893 • Andrew McAloon, Frank Taylor, Winnie Yee, USDA, Eastern Regional Research Center Agricultural Research Service; Kelly Ibsen, Robert Wooley, National Renewable Energy Laboratory, Biotechnology Center for Fuels and Chemicals, 1617 Cole Boulevard, Golden, CO, 80401-3393; NREL is a USDOE Operated by Midwest Research Institute • Battelle • Bechtel; Contract No. DE-AC36-99-GO10337. We calculated fixed and variable operating costs using percentages of direct labor and total installed capital costs. Following this methodology, we estimate that producing a gallon of ethanol using corn stover as a cellulosic feedstock would cost $1.65 in 2012 (2004 dollars). 2. Biodiesel Production Costs We based our estimate for the cost to produce biodiesel on the use of USDA's, NREL's and EIA's biodiesel computer models, along with estimates from engineering vendors that design biodiesel plants. Biodiesel fuel can be made from a wide variety of virgin vegetable oils such as canola, corn oil, cottonseed, etc. though, the operating costs (minus the costs of the feedstock oils) for these virgin vegetable oils are similar to the costs based on using soy oil as a feedstock, according to an analysis by NREL Biodiesel costs are therefore determined based on the use of soy oil, since this is the most commonly used virgin vegetable feedstock oil, and the use of recycled cooking oil (yellow grease) as a feedstock. Production costs are based on the process of continuous transesterification, which converts these feedstock oils to esters, along with the ester finishing processes and glycerol recovery. The models and vendors data are used to estimate the capital, fixed and operating costs associated with the production of biodiesel fuel, considering utility, labor, land and any other process and operating requirements, along with the prices for feedstock oils, methanol, chemicals and the byproduct glycerol. The USDA, NREL and EIA models are based on a medium sized biodiesel plant that was designed to process raw degummed virgin soy oil as the feedstock. Additionally, the EIA model also contains a representation to estimate the biodiesel production cost for a plant that uses yellow grease as a feedstock. In the USDA model, the equipment needs and operating requirements for their biodiesel plant was estimated through the use of process simulation software. This software determines the biodiesel process requirements based on the use of established engineering relationships, process operating conditions and reagent needs. To substantiate the validity and accuracy of their model, USDA solicited feedback from major biodiesel producers. Based on responses, they then made adjustments to their model and updated their input prices to year 2005. The NREL model is also based on process simulation software, though the results are adjusted to reflect NREL's modeling methods, using prices based on year 2002. The output for all of these models was provided in spreadsheet format. We also use engineering vendor estimates as another source to generate soy oil and yellow grease biodiesel production costs. These firms are primarily engaged in the business of designing biodiesel plants. The production costs are based on an average biodiesel plant located in the Midwest using feedstock oils and methanol, which are catalyzed into esters and glycerol by use of sodium hydroxide. Because local feedstock costs, distribution costs, and biodiesel plant type introduce some variability into cost estimates, we believe that using an average plant to estimate production costs provides a reasonable approach. Therefore, we simplified our analysis and used costs based on an average plant and average feedstock prices since the total biodiesel volumes forecasted are not large and represent a small fraction of the total projected renewable volumes. The models and vendor estimates are further modified to use input prices for feedstocks, byproducts and energy that reflect the effects of the fuels provisions in the Energy Act. In order to capture a range of production costs, we generated cost projections from all of the models and vendors. We present the details on these estimates in Chapter 7 of the RIA. For soy oil biodiesel production, we estimate a production cost ranging from $1.89 to $2.15 per gallon in 2012 (in 2004 dollars) using these different models and sources of information. For yellow grease derived biodiesel, we used the EIA and vendor estimates to generate total production costs which range from $1.11 to $1.56 for year 2012. With the current Biodiesel Blender Tax Credit Program, producers using virgin vegetable oil stocks receive a one dollar per gallon tax subsidy while yellow grease producers receive 50 cents per gallon, reducing the net production cost to a range of 89 to 115 cents per gallon for soy oil and 61 to 106 cents per gallon for yellow greased derived biodiesel fuel in 2012. This compares favorably to the projected wholesale diesel fuel prices of 138 cents per gallon in 2012, signifying that the economics for biodiesel are positive under the effects of the blender credit program, though the tax credit program will expire in 2008 if it is not extended. Congress may later elect to extend the blender credit program following the precedence used for extending the ethanol blending subsidies. Additionally, the Small Biodiesel Blenders Tax credit program and state tax and credit programs offer some additional subsidies and credits, though the benefits are modest in comparison to the Blender's Tax credit. 3. Diesel Fuel Costs Biodiesel fuel is blended into highway and nonroad diesel fuel, which increases the volume and therefore the supply of diesel fuel and thereby reduces the demand for refinery-produced diesel fuel. In this section, we estimate the overall cost impact, considering how much refinery based diesel fuel is displaced by the forecasted production volume of biodiesel fuel. The cost impacts are evaluated considering the production cost of biodiesel with and without the subsidy from the Biodiesel Blenders Tax credit program. Additionally, the diesel cost impacts are quantified with refinery diesel prices as forecasted by Jacob's which is based on EIA's AEO 2006. We estimate the net effect that biodiesel production has on overall cost for diesel fuel in year 2012 using total production costs for biodiesel and diesel fuel. The costs are evaluated based on how much refinery based diesel fuel is displaced by the biodiesel volumes as forecasted by EIA, accounting for energy density differences between the fuels. The cost impact is estimated from a 2004 year basis, by multiplying the production costs of each fuel by the respective changes in volumes for biodiesel and estimated displaced diesel fuel. We further assume that all of the forecasted biodiesel volume is used as transport fuel, neglecting minor uses in the heating oil market. For RFS cases, the net effect of biodiesel production on diesel fuel costs, including the biodiesel blenders' subsidy, is a reduction in the cost of transport diesel fuel costs by $114 million per year, which equates to a reduction in fuel cost of about 0.20 cents per gallon. 84 Without the subsidy, the transport diesel fuel costs are increased by $91 million per year, or an increase of 0.16 cents per gallon for transport diesel fuel. 84 Based on EIA's AEO 2006, 58.9 billion gallons of highway and off-road diesel fuel is projected to be consumed in 2012. B. Distribution Costs 1. Ethanol Distribution Costs There are two components to the costs associated with distributing the volumes of ethanol necessary to meet the requirements of the Renewable Fuels Standard (RFS):
(1)The capital cost of making the necessary upgrades to the fuel distribution infrastructure system, and
(2)the ongoing additional freight costs associated with shipping ethanol to terminals. The most comprehensive study of the infrastructure requirements for an expanded fuel ethanol industry was conducted for the Department of Energy
(DOE)in 2002. 85 That study provided the foundation for our estimates of the capital costs associated with upgrading the distribution infrastructure system as well as the freight costs to handle the increased volume of ethanol needed to meet the requirements of the RFS in 2012. Distribution costs are evaluated here for both the RFS case and for the EIA case. The 2012 reference case against which we are estimating the cost of distributing the additional volume of ethanol needed to meet the requirements of the RFS is 3.9 billion gallons. 85 Infrastructure Requirements for an Expanded Fuel Ethanol Industry, Downstream Alternatives Inc., January 15, 2002. a. Capital Costs To Upgrade Distribution System for Increased Ethanol Volume The 2002 DOE study examined two cases regarding the use of renewable fuels for estimating the capital costs for distributing additional ethanol. The first assumed that 5.1 billion gal/yr of ethanol would be used in 2010, and the second assumed that 10 billion gal/yr of ethanol would be used in the 2015 timetable. We interpolated between these two cases to provide the foundation for our estimate of the capital costs to support the use of 6.7 billion gal/yr of ethanol in 2012 for the RFS case. 86 The 10 billion gal/yr case examined in the DOE study was used as the foundation in estimating the capital costs under the EIA projected case examined in today's rule of 9.6 billion gal/yr of ethanol. 87 Our estimated capital costs in this final rule differ from those in the proposed rule for several reasons. We adjusted our capital costs from those in the proposal to reflect an increase in the cost of tank cars and barges used to ship ethanol since the DOE study was conducted. In addition, we are assuming an increased reliance on rail transport over that projected in the DOE study. 88 86 See chapter 7.3 of the Regulatory Impact Analysis associated with today's rule for additional discussion of how the results of the DAI study were adjusted to reflect current conditions in estimating the ethanol distribution infrastructure capital costs under today's rule. 87 For both the 6.7 bill gal/yr and 9.6 bill gal/yr cases, the baseline from which the DOE study cases were projected was adjusted to reflect a 3.9 bill gal/yr 2012 baseline. 88 This increased reliance on rail transport was the subject of a sensitivity analysis conducted for the proposed rule. Table VII.B.1.a-1contains our estimates of the infrastructure changes and associated capital costs for the two ethanol use scenarios examined in today's rule. Amortized over 15 years with a 7 percent cost of capital, the total capital costs equate to approximately 1.4 cents per gallon of ethanol under the RFS case and 1.2 cents per gallon under the EIA case. 89 89 These capital costs will be incurred incrementally during the period of 2007-2012 as ethanol volumes increase. For the purpose of this analysis, we assumed that all capital costs were incurred in 2007. Table VII.B.1.A-1.—Estimated Ethanol Distribution Infrastructure Capital Costs ($M) * RFS case 6.7 Bgal/yr EIA case 9.6 Bgal/yr *Fixed Facilities:* Retail 20 44 Terminals 115 241 *Mobile Facilities:* Transport Trucks 24 50 Barges 21 43 Rail Cars 172 297 Total Capital Costs 352 675 * Relative to a 3.9 billion gal/yr reference case. b. Ethanol Freight Costs The Energy Information Administration
(EIA)translated the ethanol freight cost estimates in the DOE study to a census division basis. 90 For this final rule, we translated the EIA projections into State-by-State and national average freight costs to align with our State-by-State ethanol use estimates. Not including capital recovery, we estimate that the freight cost to transport ethanol to terminals would range from 4 cents per gallon in the Midwest to 25 cents per gallon to the West Coast. On a national basis, this averages to 11.3 cents per gallon of ethanol under the RFS case and 11.9 cents per gallon under the EIA case. 91 We adjusted the estimated ethanol freight costs from those in the proposal by increasing the cost of shipping ethanol to satellite versus hub terminals, by increasing the cost of gathering ethanol for large volume shipments to hub terminals, and by increasing the percentage of ethanol delivered to large volume terminals versus the volume delivered to lesser volume terminals. 92 90 Petroleum Market Model of the National Energy Modeling System, Part 2, March 2006, DOE/EIA-059 (2006), *http://tonto.eia.doe.gov/FTPROOT/modeldoc/m059(2006)-2.pdf.* 91 See Chapter 7.3 of the RIA. 92 Hub terminals refer to those terminals where ethanol is delivered in large volume shipments such as by unit train (consisting of 70 tank cars or more) or marine barges/tanker. Satellite terminals are those terminals that are either supplied from a hub terminal or receive ethanol shipments in smaller quantities directly from the producer. See Chapter 7 of the RIA regarding how these estimates were adjusted from those in the proposal and the check of our estimates against current ethanol freight rates. Including the cost of capital recovery for the necessary distribution facility changes, we estimate the national average cost of distributing ethanol to be 12.7 cents per gallon under the RFS case and 13.1 cents per gallon under the EIA case. 93 Thus, we estimate the total cost for producing and distributing ethanol to be between $1.39 and $1.45 per gallon of ethanol, on a nationwide average basis. This estimate includes both the capital costs to upgrade the distribution system and freight costs. 93 All capital costs were assumed to be incurred in 2007 and were amortized over 15 years at a 7 percent cost of capital. 2. Biodiesel Distribution Costs The volume of biodiesel used by 2012 under the RFS is estimated at 300 million gallons per year. The 2012 baseline case against which we are estimating the cost of distributing the additional volume of biodiesel is 30 million gallons. 94 94 2004 baseline of 25 million gallons grown with diesel demand to 2012. The capital costs associated with distribution of biodiesel are higher per gallon than those associated with the distribution of ethanol due to the need for storage tanks, blending systems, barges, tanker trucks and rail cars to be insulated and in many cases heated during the winter months. 95 In the proposal, we estimated that these capital costs would be approximately $50,000,000. We adjusted our estimate of these capital costs for this final rule based on additional information regarding the cost to install necessary storage and blending equipment at terminals and the need for additional rail tank cars for biodiesel. 96 As discussed in the RIA, we now estimate that handling the increased biodiesel volume will require a total capital cost investment of $145,500,000 which equates to about 6 cents per gallon of new biodiesel volume. 97 95 See Chapter 1.3 of the Regulatory Impact Analysis associated with today's rule for a discussion of the special handling requirements for biodiesel under cold conditions. 96 Biodiesel rail tank cars typically have a capacity of 25,500 gallons as opposed to 30,000 gallons for an ethanol tank car. Thus, additional tank cars are needed to transport a given volume of biodiesel relative to the same volume of ethanol. 97 Capital costs will be incurred incrementally over the period of 2007-2012 as biodiesel volumes increase. For the purpose of this analysis, all capital costs were assumed to be incurred in 2007 and were amortized over 15 years at a 7 percent cost of capital. In the proposal, we estimated that the freight costs for ethanol may adequately reflect those for biodiesel as well. In response to comments, we sought additional information regarding the freight costs for biodiesel. This information indicates that freight costs for biodiesel are typically 30 percent higher than those for ethanol which translates into an estimate of 15.5 cents per gallon for biodiesel freight costs on a national average basis. 98 98 The estimated ethanol freight costs were increased by 30 percent to arrive at the estimate of biodiesel freight costs. Including the cost of capital recovery for the necessary distribution facility changes, we estimate the cost of distributing biodiesel to be 21.5 cents per gallon. Depending on whether the feedstock is waste grease or virgin oil, we estimate the total cost for producing and distributing biodiesel to be between $1.33 and $2.11 per gallon of biodiesel, on a nationwide average basis. 99 This estimate includes both the capital costs to upgrade the distribution system and freight costs, and the wide range reflects differences in different types of production feedstocks. 99 See Section VII.A.2. of this preamble regarding biodiesel production costs. We estimated 2012 production costs of $1.89 per gal for soy-derived biodiesel and $1.11 per gal for yellow grease derived biodiesel. C. Estimated Costs to Gasoline To estimate the cost of increased use of renewable fuels, the cost savings from the phase out of MTBE and the production cost of alkylate, we relied on refinery modeling conducted by Jacob's Consultancy that established baselines based on 2004 volumes, which were then used to project a reference case and 2 control cases for 2012. The contractor developed a five region, U.S. demand model in which specific regional clean product demands are sold at hypothetical regional terminals. 1. Description of Cases Modeled a. Base Case
(2004)The baseline case was established by modeling fuel volumes for 2004, with data on fuel properties provided to the contractor by EPA. Fuel property data for this base case was built off of 2004 refinery batch reports provided to EPA; however, the base case assumed sulfur standards based on gasoline data in 2004, not with fully phased in Tier 2 gasoline standards at the 30 ppm level. In addition we assumed the phase-in of 15 ppm sulfur standards for highway, nonroad, locomotive and marine diesel fuel. The supply/demand balance for the U.S. was based on gasoline volumes from EIA and the California Air Resources Board (CARB). Our decision to use 2004 rather than 2005 as the baseline year was because of the refinery upset conditions associated with the Gulf Coast hurricanes in 2005. b. Reference Case
(2012)The reference case was based on modeling the base case, using 2012 fuel prices, and scaling the 2004 fuel volumes to 2012 based on growth in fuel demand. In addition, we scaled MTBE and ethanol upward, in proportion to gasoline growth, and assumed the RFS program would not be in effect. For example, if the PADD 1 gasoline pool MTBE oxygen was 0.5 wt% in 2004, the reference case assumed it should remain at 0.5 wt%. Finally, we assumed the MSAT 1 standards would remain in place as would the RFG oxygen mandate. We assumed the crude slate quality in 2012 is the same as the baseline case. c. Control Cases
(2012)Two control cases were run for 2012. The assumptions for each of the control cases are summarized below Control Case 1 (RFS case): 6.7 billion gallons/yr
(BGY)of ethanol in gasoline; it reflects the renewable fuel mandate. We have also assumed that 0.3 billion gallons of biodiesel will be consumed as reflected in Table II.A.1-1. In addition, it is assumed that no MTBE is in gasoline, MSAT1 is in place, the psi waiver for conventional gasoline containing 10 volume percent ethanol is in effect, the RFS is in effect, and there is no RFG oxygenate mandate. Control Case 2 (EIA case): Same as Control Case 1, except the ethanol volume in gasoline is 9.6 BGY. 2. Overview of Cost Analysis Provided by the Contractor Refinery Model The estimated cost of increased use of renewable fuels, the cost savings from the phase out of MTBE and the cost of converting some of the former MTBE feedstocks to produce alkylate, isooctane, and isooctene is provided by the output of the refinery model. As described in VII.C.1, the cost analysis was conducted by comparing the 2012 reference case with the two control cases which are assumed to take place in 2012. The major factors which impact the costs in the refinery model are
(1)blending in more ethanol,
(2)adjusting the gasoline blending to lower RVP,
(3)removing the MTBE,
(4)converting MTBE feedstocks to other high quality replacement, and
(5)adjusting for the change in gasoline energy density. The first is the addition of ethanol to the gasoline pool. The refinery model estimates the cost impact of increasing the volume of ethanol in the reference case from 3.94 billion gallons to 6.67 and 9.60 billion gallons in the RFS and EIA modeled cases, respectively. The estimated production prices for ethanol for the RFS and EIA cases are provided above in Section VII.A. We also show the results with the federal and state subsidies applied to the production price of ethanol. The addition of ethanol to wintertime gasoline, and to summertime RFG, will cause an increase of approximately 1 psi in RVP which needs to be offset to maintain constant RVP levels. One method that refiners could choose to offset the increase in RVP is to reduce the butane levels in their gasoline. To some extent, the modeling results showed some occurrences of that, but it also did not report an overall increase in butane sales as a result of the increased use of ethanol. To convert the captive MTBE over to alkylate, after the rejection of methanol, refiners will need to combine refinery-produced isobutane with the isobutylene that was used as a feedstock for MTBE. The use of the isobutane will reduce the RVP of the gasoline pool from which it comes, helping to offset the RVP impacts of ethanol. Also, the increased production of alkylate provides a low RVP gasoline blendstock which offsets a portion of the cracked stocks produced by the fluidized catalytic cracker unit. Other means that the refinery model used to offset the high blending RVP of ethanol included purchasing gasoline components with lower RVP, producing more poly gasoline which has low RVP and selling more high-RVP naphtha to petrochemical sales. 3. Overall Impact on Fuel Cost Based on the refinery modeling conducted for today's rule, we have calculated the costs of these fuels changes that will occur for the RFS and EIA cases. The costs are expressed two different ways. First, we express the cost of the program without the ethanol consumption subsidies in which the costs are based on the total accumulated cost of each of the fuels changes. Second, we express the cost with the ethanol consumption subsidies included since the subsidized portion of the renewable fuels costs will not be represented to the consumer in its fuels costs paid at the pump, but instead by being paid through the state and federal tax revenues. In all cases, the capital costs are amortized at 7 percent return on investment (ROI), and based on 2006 dollars. a. Cost Without Ethanol Subsidies Table VII.C.3.a-1 summarizes the costs without ethanol subsidies for each of the two control cases, including the cost for each aspect of the fuel changes, and the aggregated total and the per-gallon costs for all the fuel changes. 100 This estimate of costs reflects the changes in gasoline that are occurring with the expanded use of ethanol, including the corresponding removal of MTBE. These costs include the labor, utility and other operating costs, fixed costs and the capital costs for all the fuel changes expected. The per-gallon costs are derived by dividing the total costs over all U.S. gasoline projected to be consumed in 2012. We excluded federal and state ethanol consumption subsidies which avoids the transfer payments caused by these subsidies that would hide a portion of the program's costs. 100 EPA typically assesses social benefits and costs of a rulemaking. However, this analysis is more limited in its scope by examining the average cost of production of ethanol and gasoline without accounting for the effects of farm subsidies that tend to distort the market price of agricultural commodities. Table VII.C.3.A-1.—Estimated Cost Without Ethanol Consumption Subsidies [Million dollars and cents per gallon; 7% ROI and 2006 dollars] RFS case 6.8 billion gals incremental to reference case EIA case 9.6 billion gals incremental to reference case EIA case 9.6 billion gals incremental to RFS case Capital Costs ($MM) −5,878 −7,311 −1,433 Amortized Capital Costs ($MM/yr) −647 −804 −158 Fixed Operating Cost ($MM/yr) −178 −222 −43 Variable Operating Cost ($MM/yr) −201 −491 −290 Fuel Economy Cost ($MM/yr) 1,848 3,255 1407 Total Cost ($MM/yr) 823 1739 915 Capital Costs (c/gal of gasoline) −0.40 −0.49 −0.10 Fixed Operating Cost (c/gal of gasoline) −0.11 −0.14 −0.03 Variable Operating Cost (c/gal of gasoline) −0.12 −0.30 −0.18 Fuel Economy Cost (c/gal of gasoline) 1.13 1.98 0.86 Total Cost Excluding Subsidies (c/gal of gasoline) 0.50 1.06 0.56 Our analysis shows that when considering all the costs associated with these fuel changes resulting from the expanded use of subsidized ethanol that these various possible gasoline use scenarios will increase fuel costs by $820 million or $1,740 million in the year 2012 for the RFS and EIA cases, respectively. Expressed as per-gallon costs, these fuel changes would increase fuel costs by 0.50 to 1.1 cents per gallon of gasoline. b. Gasoline Costs Including Ethanol Consumption Tax Subsidies Table VII.C.3.b-1 expresses the total and per-gallon gasoline costs for the two control scenarios with the federal and state ethanol subsidies included. The federal tax subsidy is 51 cents per gallon for each gallon of new ethanol blended into gasoline. The state tax subsidies apply in 5 states and range from 1.6 to 29 cents per gallon. The cost reduction to the fuel industry and consumers is estimated by multiplying the subsidy times the volume of new ethanol estimated to be used in the state. The per-gallon costs are derived by dividing the total costs over all U.S. gasoline projected to be consumed in 2012. Table VII.C.3.B-1.—Estimated Cost Including Ethanol Consumption Subsidies [Million dollars and cents per gallon; 7% ROI and 2006 dollars] RFS case 6.8 billion gals incremental to reference case EIA case 9.6 billion gals incremental to reference case EIA case 9.6 billion gals incremental to RFS case Total Cost ($MM/yr) 823 1739 915 Federal Subsidy ($MM/yr) −1376 −2865 −1489 State Subsidies ($MM/yr) −5 −31 −26 Revised Total Cost ($MM/yr) −558 −1158 −600 Per-Gallon Cost Excluding Subsidies (c/gal of gasoline) 0.50 1.06 0.56 Federal Subsidy (c/gal of gasoline) −0.84 −1.74 −0.90 State Subsidies (c/gal of gasoline) −0.003 −0.02 −0.02 Total Cost Including Subsidies (c/gal of gasoline) −0.34 −0.71 −0.37 The cost including subsidies better represents gasoline's production cost as reflected to the fuel industry as a whole and to consumers “at the pump” because the federal and state subsidies tend to hide a portion of the actual costs. Our analysis estimates that the fuel industry and consumers will see a 0.34 and 0.71 cent per gallon decrease in the apparent cost of producing gasoline for the RFS and EIA cases, respectively. VIII. What Are the Impacts of Increased Ethanol Use on Emissions and Air Quality? In this section, we evaluate the impact of increased production and use of renewable fuels on emissions and air quality in the U.S., particularly ethanol and biodiesel. In performing these analyses, we compare the emissions which would have occurred in the future if fuel quality had remained unchanged from pre-Act levels to those which will be either required under the Energy Policy Act of 2005 (Energy Act or the Act) or exist due to market forces. This approach differs from that traditionally taken in EPA regulatory impact analyses. Traditionally, we would have compared future emissions with and without the requirement of the Energy Act. However, as described in Section II, we expect that total renewable fuel use in the U.S. in 2012 to exceed the Act's requirements even in the absence of the RFS program. Thus, a traditional regulatory impact analysis would have shown no impact on emissions or air quality. This is because, strictly speaking, if the same volume and types of renewable fuels are produced and used with and without the RFS program, the RFS program has no impact on fuel quality and thus, no impact on emissions or air quality. However, levels of renewable fuel use are increasing dramatically relative to both today and the recent past, with corresponding impacts on emissions and air quality. We believe that it is appropriate to evaluate these changes here, regardless of whether they are occurring due to economic forces or Energy Act requirements. In the process of estimating the impact of increased renewable fuel use, we also include the impact of reduced use of MTBE in gasoline. It is the increased production and use of ethanol which is facilitating the continued production of RFG which meets both commercial and EPA regulatory specifications without the use of MTBE. Because of this connection, we found it impractical to isolate the impact of increased ethanol use from the removal of MTBE. A. Effect of Renewable Fuel Use on Emissions 1. Emissions From Gasoline Fueled Motor Vehicles and Equipment Several models of the impact of gasoline quality on motor vehicle emissions have been developed since the early 1990's. We evaluated these models and selected those which were based on the most comprehensive set of emissions data and developed using the most advanced statistical tools for this analysis. Still, as will be described below, significant uncertainty exists as to the effect of these gasoline components on emissions from both motor vehicle and nonroad equipment, particularly from the latest vehicle and engine models equipped with the most advanced emission controls. Pending adequate funding, we plan to conduct significant vehicle and equipment testing over the next several years to improve our estimates of the impact of these additives and other gasoline properties on emissions. We hope that the results from these test programs will be available for reference in the future evaluations of the emission and air quality impacts of U.S. fuel programs required by the Act. 101 101 Subject to funding. The remainder of this sub-section is divided into three parts. The first evaluates the impact of increased ethanol use and decreased MTBE use on gasoline quality. The second evaluates the impact of increased ethanol use and decreased MTBE use on motor vehicle emissions. The third evaluates the impact of increased ethanol use and decreased MTBE use on nonroad equipment emissions. a. Gasoline Fuel Quality For the final rulemaking, we estimate the impact of increased ethanol use and decreased MTBE use on gasoline quality using refinery modeling conducted specifically for the RFS rulemaking. 102 In general, adding ethanol to gasoline reduces the aromatic content of conventional gasoline and the mid- and high-distillation temperatures (e.g., T50 and T90). RVP increases except in areas where ethanol blends are not provided a 1.0 RVP waiver of the applicable RVP standards in the summer. With the exception of RVP, adding MTBE directionally produces the same impacts. Thus, the effect of removing MTBE results in essentially the opposite impacts. Neither oxygenate is expected to affect sulfur levels, as refiners control sulfur independently in order to meet the Tier 2 sulfur standards. 102 Refinery modeling performed in support of the original RFG rulemaking is also used to help separate the effects of the two oxygenates. The impacts of oxygenate use are smaller with respect to RFG. This is due to RFG's VOC and toxics emission performance specifications, which limit the range of feasible fuel quality values. Thus, oxygenate type or level does not consistently affect the RVP level and aromatic and benzene contents of RFG. Table VIII.A.1.a-1 shows the fuel quality of a typical summertime, non-oxygenated conventional gasoline and how these qualities change with the addition of 10 volume percent ethanol. Similarly, the table shows the fuel quality of a typical MTBE RFG blend and how fuel quality might change with either ethanol use or simply MTBE removal. All of these fuels are based, in whole or in part, on projections made by Jacobs in their recent refinery modeling performed for EPA and therefore, represent improvements over the projections made for the NPRM. Please see Chapter 2 of the RIA for a detailed description of the methodologies used to determine the specific changes in projected fuel quality. As discussed there, we use the Jacobs model projections of RFG fuel quality directly in our emission modeling. For conventional gasoline, we use the Jacobs modeling described in Section VII to determine the change in fuel quality due to ethanol use and apply this change to base fuel quality estimates contained in EPA's NMIM emission inventory model. Sulfur is not shown in Table VIII.A.1.a-1, as it is held constant at 30 ppm, which is the average Tier 2 sulfur standard applicable to all gasoline sold in the U.S. in the timeframe of our emission analyses. Table VIII.A.1.A-1.—Typical Summertime Fuel Quality Fuel parameter Conventional gasoline Typical 9 RVP Ethanol blend Reformulated gasoline a MTBE blend Ethanol blend Non-oxygenated blend RVP
(psi)8.7 9.7 7.0 7.0 7.0 T50 218 205 179 184 175 T90 332 329 303 335 309 E200 41 50 60 58 52 E300 82 82 89 82 88 Aromatics (vol%) 32 27 20 20 20 Olefins (vol%) 7.7 7.7 4 14 15 Oxygen (wt%) 0 3.5 2.1 3.5 0 Benzene (vol%) 1.0 1.0 0.74 0.70 0.72 a MTBE blend—Reference Case PADD 1 South, Ethanol blend—RFS Case PADD 1 North, Non-oxy blend. −RFS Case PADD 1 South. b. Emissions From Motor Vehicles We use the EPA Predictive Models to estimate the impact of gasoline fuel quality on exhaust VOC and NO <sup>X</sup> emissions from motor vehicles. These models were developed in 2000, in support of EPA's response to California's request for a waiver of the RFG oxygen mandate. These models represent a significant update of the EPA Complex Model. However, they are still based on emission data from Tier 0 vehicles (roughly equivalent to 1990 model year vehicles). We based our estimates of the impact of fuel quality on CO emissions on the EPA MOBILE6.2 model. We base our estimates of the impact of fuel quality on exhaust toxic emissions (benzene, formaldehyde, acetaldehyde, and 1,3-butadiene) primarily on the MOBILE6.2 model, updated to reflect the effect of fuel quality on exhaust VOC emissions per the EPA Predictive Models. Very limited data are available on the effect of gasoline quality on PM emissions. Therefore, the effect of increased ethanol use on PM emissions can only be qualitatively discussed. In responding to California's request for a waiver of the RFG oxygen mandate in 2000, we found that both very limited and conflicting data were available on the effect of fuel quality on exhaust emissions from Tier 1 and later vehicles. 103 Thus, we assumed at the time that changes to gasoline quality would not affect VOC, CO and NO <sup>X</sup> exhaust emissions from these vehicles. 104 Very little additional data have been collected since that time on which to modify this assumption. Consequently, for our primary analysis for today's final rule we have maintained the assumption that changes to gasoline do not affect exhaust emissions from Tier 1 and later technology vehicles. 103 The one exception was the impact of sulfur on emissions from these later vehicles, which is not an issue here due to the fact that renewable fuel use is not expected to change sulfur levels significantly. 104 An exception is that MOBILE6.2 applies the effect of oxygenate on CO emissions to Tier 1 and later vehicles which are expected to be high emitters based on their age and mileage. For the NPRM, we evaluated one recent study by the Coordinating Research Council
(CRC)which assessed the impact of ethanol and two other fuel properties on emissions from twelve 2000-2004 model year vehicles (CRC study E-67). Based on comments received on the NPRM, we evaluated four additional studies of the fuel-emission effects of recent model year vehicles. The results of these test programs indicate that emissions from these late model year vehicles are likely sensitive to changes in fuel properties. However, both the size and direction of the effects are not consistent between the various studies. More testing is still needed before confident predictions of the effect of fuel quality on emissions from these vehicles can be made. In the NPRM, we developed two sets of assumptions regarding the effect of fuel quality on emissions from Tier 1 and later vehicles to reflect this uncertainty. A primary analysis assumed that exhaust emissions from Tier 1 and later vehicles are not sensitive to fuel quality. This is consistent with our analysis of California's request for a waiver of the RFG oxygen mandate. A sensitivity analysis assumed that the NMHC and NO <sup>X</sup> emissions from Tier 1 and later vehicles were as sensitive to fuel quality as Tier 0 vehicles. Only one effect of fuel quality on CO emissions was assumed, that contained in EPA's MOBILE6.2 emission inventory model. The five available studies of Tier 1 and later vehicles support continuing this approach for exhaust NMHC and NO <sup>X</sup> emissions. The assumptions supporting both our primary and sensitivity analyses reasonably bracket the results of the five studies. However, we have decided to perform a sensitivity analysis for CO emissions, as well. In this case, we apply the fuel-emission effects from MOBILE6.2 for Tier 0 vehicles to Tier 1 and later vehicles. This is analogous to the approach taken for exhaust NMHC and NO <sup>X</sup> emissions. We base our estimates of fuel quality on non-exhaust VOC and benzene emissions on the EPA MOBILE6.2 model. The one exception to this is the effect of ethanol on permeation emissions through plastic fuel tanks and elastomers used in fuel line connections. Recent testing has shown that ethanol increases permeation emissions, both by permeating itself and increasing the permeation of other gasoline components. This effect was included in EPA's analysis of California's most recent request for a waiver of the RFG oxygen requirement, but is not in MOBILE6.2. 105 Therefore, we have added the effect of ethanol on permeation emissions to MOBILE6.2's estimate of non-exhaust VOC emissions in assessing the impact of gasoline quality on these emissions. 105 For more information on California's request for a waiver of the RFG oxygen mandate and the Decision Document for EPA's response, see *http://www.epa.gov/otaq/rfg_regs.htm#waiver.* No models are available which address the impact of gasoline quality on PM emissions. Very limited data indicate that ethanol blending might reduce exhaust PM emissions under very cold weather conditions (e.g., −20 °F to 0 °F). Very limited testing at warmer temperatures (e.g., 20 °F to 75 °F) shows no definite trend in PM emissions with oxygen content. Thus, for now, no quantitative estimates can be made regarding the effect of ethanol use on direct PM emissions. Table VIII.A.1.b-1 presents the average per vehicle (2012 fleet) emission impacts of three types of RFG: Non-oxygenated, a typical MTBE RFG as has been marketed in the Gulf Coast, and a typical ethanol RFG which has been marketed in the Midwest. Table VIII.A.1.B-1.—Effect of RFG on Per Mile Emissions From Tier 0 Vehicles Relative to a Typical 9psi RVP Conventional Gasoline a Pollutant Source Non-Oxy RFG (percent) 11 Volume percent MTBE 10 Volume percent ethanol Exhaust Emissions VOC EPA Predictive Models −13.4 −15.3 −9.7 NO <sup>X</sup> −2.4 −1.7 7.3 CO MOBILE6.2 −22 −31 −36 Exhaust Benzene EPA Predictive and Complex Models −21.2 −29.7 −38.9 Formaldehyde −5.9 19.4 2.3 Acetaldehyde −0.2 −9.5 173.7 1,3-Butadiene 20.9 −29.2 6.1 Non-Exhaust Emissions VOC MOBILE6.2 & CRC E-65 −30 −30 −18 Benzene MOBILE6.2 & Complex Models −40 −43 −32 a Average per vehicle effects for the 2012 fleet during summer conditions. As can be seen, all three types of RFG produce significantly lower emissions of VOC, CO and benzene than conventional gasoline. The impact of ethanol RFG on non-exhaust VOC emissions is lower than the other two types of RFG due to the impact of ethanol on permeation emissions. The impact of RFG on emissions of NO <sup>X</sup> and the other air toxics depends on the type of RFG blend. The most notable effect on toxic emissions in percentage terms is the 173 percent increase in acetaldehyde with the use of ethanol. However, as will be seen below, base acetaldehyde emissions are low relative to the other toxics. While not shown, the total mass emissions of the four toxic pollutants always decreases, as benzene is by far the largest constituent. It should be noted that these comparisons assume that all gasoline blends meet EPA's Tier 2 gasoline sulfur standard of 30 ppm. Prior to the Tier 2 program, RFG contained less sulfur than conventional gasoline and reduced NO <sup>X</sup> emissions to a greater degree compared to conventional gasoline. Historically, no non-oxygenated RFG was sold, due to the requirement that RFG contain at least 2.0 weight percent oxygen. However, with the Energy Act's removal of this requirement, all three types of RFG blends can be sold today. Increased use of ethanol in RFG would therefore either replace MTBE RFG or non-oxygenated RFG. The former has already occurred in many areas, as MTBE was essentially removed from the U.S. gasoline market by the end of 2006. The impact of using ethanol in RFG in lieu of MTBE or no oxygenate can be seen from comparing the relative impacts of the various RFG blends shown in Table VIII.A.1.b-1. Blending RFG with ethanol instead of MTBE or no oxygenate will increase VOC and NO <sup>X</sup> emissions and decrease CO emissions. Exhaust benzene and formaldehyde emissions will decrease, but non-exhaust benzene, acetaldehyde, and 1,3-butadiene emissions will increase. All of these impacts are on a per vehicle basis and apply to Tier 0 vehicles only. The overall impact of increased ethanol use on total emissions of these various pollutants is described below. Table VIII.A.1.b-2 presents the effect of blending either MTBE or ethanol into conventional gasoline while matching octane. Table VIII.A.1.B-2.—Effect of MTBE and Ethanol in Conventional Gasoline on Tier 0 Vehicle Emissions Relative to a Typical Non-Oxygenated Conventional Gasoline a Pollutant Source 11 Volume percent MTBE 10 Volume percent ethanol b Exhaust VOC EPA Predictive Models −9.2 −7.4 NO <sup>X</sup> −2.6 7.7 CO c MOBILE6.2 −6/−11 −11/−19 Exhaust Benzene EPA Predictive and Complex Models −22.8 −24.9 Formaldehyde +21.3 +6.7 Acetaldehyde +0.8 +156.8 1,3-Butadiene −3.7 −13.2 Non-Exhaust VOC MOBILE6.2 Zero +30 Non-Exhaust Benzene MOBILE6.2 & Complex Models −9.5 +15.8 a Average per vehicle effects for the 2012 fleet during summer conditions. b Assumes a 1.0 psi RVP waiver for ethanol blends. c The first figure shown applies to normal emitters; the second applies to high emitters. Use of either oxygenate reduces exhaust VOC and CO emissions, but increases NO <sup>X</sup> emissions. The ethanol blend increases non-exhaust VOC emissions due to the commonly granted 1.0 psi waiver of the RVP standard, as well as increased permeation emissions. Both oxygenated blends reduce exhaust benzene and 1,3-butadiene emissions. As above, ethanol increases non-exhaust benzene and acetaldehyde emissions. While small amounts of MTBE may have still been used in CG in 2004, for our reference case we have assumed that all MTBE use was in RFG. Therefore, we are not predicting any emissions impact related to removing MTBE from conventional gasoline. Increased use of conventional ethanol blends will be in lieu of non-oxygenated conventional gasoline. Thus, the more relevant column in Table VII.A.1.b-2 for our modeling is the last column, which shows the emission impact of a 10 volume percent ethanol blend relative to non-oxygenated gasoline. The exhaust emission effects shown above for VOC and NO <sup>X</sup> emissions only apply to Tier 0 vehicles in our primary analysis. For example, MOBILE6.2 estimates that 34 of exhaust VOC emissions and 16 of NO <sup>X</sup> emissions from gasoline vehicles in 2012 come from Tier 0 vehicles. In the sensitivity analysis, these effects are extended to all gasoline vehicles. The effect of RVP and permeation on non-exhaust VOC emissions is temperature dependent. The figures shown above are based on the distribution of temperatures occurring across the U.S. in July. We received several comments related to the effect of ethanol on emissions from onroad vehicles. None of the comments led us to change the basic approach taken to estimating the impact of changing fuel quality described above. Several comments suggested that we expand our discussion of the uncertainty in these fuel effects (as well as the effects of fuel quality on emissions from nonroad equipment and diesels described below). While such an expanded discussion might be generally desirable, the lack of relevant emission data from late model vehicles and equipment prevents this. We believe that we have adequately described the uncertainty in the emission estimates presented below and our plans to obtain more data in order to improve these estimates in the near future. c. Nonroad Equipment To estimate the effect of gasoline quality on emissions from nonroad equipment, we used EPA's NONROAD emission model. We used the 2005 version of this model, NONROAD2005, which includes the effect of ethanol on permeation emissions from most nonroad equipment. Only sulfur and oxygen content affect exhaust VOC, CO and NO <sup>X</sup> emissions in NONROAD. Since sulfur level is assumed to remain constant, the only difference in exhaust emissions between conventional and reformulated gasoline is due to oxygen content. Table VIII.A.1.c-1 shows the effect of adding 11 volume percent MTBE or 10 volume percent ethanol to non-oxygenated gasoline on these emissions. Table VIII.A.1.C-1.—Effect MTBE and Ethanol on Nonroad Exhaust Emissions Relative to a Typical Non-Oxygenated Gasoline Base fuel 4-Stroke engines 11 Volume percent MTBE 10 Volume percent ethanol 2-Stroke engines 11 Volume percent MTBE 10 Volume percent ethanol Exhaust VOC −9 −16 −1 −2 Non-Exhaust VOC 0 26 0 26 CO −13 −22 −13 −23 NO <sup>X</sup> +23 +40 +37 +65 As can be seen, higher oxygen content reduces exhaust VOC and CO emissions significantly, but also increases NO <sup>X</sup> emissions. However, NO <sup>X</sup> emissions from these engines tend to be fairly low to start with, given the fact that these engines run much richer than stoichiometric. Thus, a large percentage increase of a relative low base value can be a relatively small increase in absolute terms. Evaporative emissions from nonroad equipment are impacted by only RVP, and permeation by ethanol content. Both the RVP increase due to blending of ethanol and its permeation effect cause non-exhaust VOC emissions to increase with the use of ethanol in nonroad equipment. The 26 percent effect represents the average impact across the U.S. in July for both 2-stroke and 4-stroke equipment. We updated the NONROAD2005 hose permeation emission factors for small spark-ignition engines and recreational marine watercraft to reflect the use of ethanol. For nonroad toxics emissions, we base our estimates of the impact of fuel quality on the fraction of exhaust VOC emissions represented by each toxic on MOBILE6.2 (i.e., the same effects predicted for onroad vehicles). The National Mobile Inventory Model
(NMIM)contains estimates of the fraction of VOC emissions represented by the various air toxics based on oxygenate type (none, MTBE or ethanol). However, estimates for nonroad gasoline engines running on different fuel types are limited, making it difficult to accurately model the impacts of changes in fuel quality. In the recent final rule addressing mobile air toxic emissions, EPA replaced the toxic-related fuel effects contained in NMIM with those from MOBILE6.2 for onroad vehicles. 106 We follow the same methodology here. Future testing could significantly alter these emission impact estimates. 106 71, **Federal Register** , 15804, March 29, 2006. 2. Diesel Fuel Quality: Biodiesel EPA assessed the impact of biodiesel fuel on emissions in 2002 and published a draft report summarizing the results. 107 This report included a technical analysis of biodiesel effects on regulated and unregulated pollutants from diesel powered vehicles and concluded that biodiesel fuels improved PM, HC and CO emissions of diesel engines while slightly increasing their NO <sup>X</sup> emissions. 107 “A Comprehensive Analysis of Biodiesel Impacts on Exhaust Emissions,” Draft Technical Report, U.S. EPA, EPA420-P-02-001, October 2002. *http://www.epa.gov/otaq/models/biodsl.htm* . While the conclusions reached in the 2002 EPA report relative to biodiesel effects on VOC, CO and PM emissions have been generally accepted, the magnitude of the B20 effect on NO <sup>X</sup> remains controversial due to conflicting results from different studies. Significant new testing is being planned with broad stakeholder participation and support in order to better estimate the impact of biodiesel on NO <sup>X</sup> and other exhaust emissions from the in-use fleet of diesel engines. We hope to incorporate the data from such additional testing into the analyses for other studies required by the Energy Act in 2008 and 2009, and into a subsequent rule to set the RFS program standard for 2013 and later. 3. Renewable Fuel Production and Distribution Areas experiencing increased renewable production will experience the corresponding emission increases associated with their production. The primary impact of renewable fuel production and distribution regards ethanol, since it is expected to be the predominant renewable fuel used in the foreseeable future. We approximate the impact of increased ethanol and biodiesel production, including corn and soy farming, on emissions based on DOE's GREET model, version 1.7. In addition, we develop a second estimate of emissions from ethanol production facilities using estimates of emissions from current ethanol plants obtained from the States. We also include emissions effects resulting from the transport of increased volumes of renewable fuels and decreased volumes of gasoline and diesel fuel. These emissions are summarized in Table VIII.A.3-1. Table VIII.A.3-1.—Well-to-Pump Emissions for Producing and Distributing Renewable Fuels [Grams per gallon ethanol or biodiesel] a Pollutant GREET1.7 Current ethanol plants Future ethanol plants GREET1.7 + state data Current ethanol plants Future ethanol plants Biodiesel—GREET1.7 VOC 1.8 1.8 3.6 3.2 37.6 CO 4.0 4.1 4.4 4.3 12.7 NO <sup>X</sup> 11.4 11.4 10.8 13.0 25.1 PM10 4.9 4.9 6.1 2.8 4.8 SO <sup>X</sup> 6.4 6.4 7.2 9.7 21.8 a Includes credit for reduced distribution of gasoline and diesel fuel. At the same time, areas with refineries might experience reduced emissions, not necessarily relative to current emission levels, but relative to those which would have occurred in the future had renewable fuel use not risen. However, to the degree that increased renewable fuel use reduces imports of gasoline and diesel fuel, as opposed to the domestic production of these fuels, these reduced refinery emissions will occur overseas and not in the U.S. Similarly, areas with MTBE production facilities might experience reduced emissions from these plants as they cease producing MTBE. However, many of these plants may be converted to produce other gasoline blendstocks, such as iso-octane or alkylate. In this case, their emissions are not likely to change substantially. B. Impact on Emission Inventories We use the NMIM to estimate emissions under the various ethanol scenarios on a county by county basis. NMIM basically runs MOBILE6.2 and NONROAD2005 with county-specific inputs pertaining to fuel quality, ambient conditions, levels of onroad vehicle VMT and nonroad equipment usage, etc. We ran NMIM for two months, July and January. We estimate annual emission inventories by summing the two monthly inventories and multiplying by six. As described above, we removed the effect of gasoline fuel quality on exhaust VOC and NO <sup>X</sup> emissions from the onroad motor vehicle inventories which are embedded in MOBILE6.2. We then applied the exhaust emission effects from the EPA Predictive Models. In our primary analysis, we only applied these EPA Predictive Model effects to exhaust VOC and NO <sup>X</sup> emissions from Tier 0 vehicles. In a sensitivity case, we applied them to exhaust VOC and NO <sup>X</sup> emissions from all vehicles. Regarding the effect of fuel quality on emissions of four air toxics from nonroad equipment (in terms of their fraction of VOC emissions), in all cases we replaced the fuel effects contained in NMIM with those for motor vehicles contained in MOBILE6.2. The projected emission inventories for the primary analysis are presented first, followed by those for the sensitivity analysis. 1. Primary Analysis The national emission inventories for VOC, CO and NO <sup>X</sup> in 2012 with current fuels (i.e., “reference fuel”) are summarized in Table VIII.B.1-1. Also shown are the changes in emissions projected for the two levels of ethanol use (i.e., “control cases”) described in Section VI. Table VIII.B.1-1.—2012 Emissions Nationwide From Gasoline Vehicles and Equipment Under Several Ethanol Use Scenarios—Primary Analysis [Tons per year] 108 Pollutant Inventory Reference case Change in inventory in control cases RFS case EIA case VOC 5,882,000 18,000 43,000 NO <sup>X</sup> 2,487,000 23,000 40,000 CO 55,022,000 −483,000 −1,366,000 Benzene 178,000 −3,200 −7,200 Formaldehyde 40,400 −600 −200 Acetaldehyde 19,900 3,400 7,100 1,3-Butadiene 18,900 −200 −300 Both VOC and NO <sup>X</sup> emissions are projected to increase with increased use of ethanol. However, the increases are small, generally less than 2 percent. CO emissions are projected to decrease by about 0.9 to 2.5 percent. Benzene emissions are projected to decrease by 1.8 to 4.0 percent. Formaldehyde emissions are projected to decrease slightly, on the order of 0.5 to 1.5 percent. 1,3-butadiene emissions are projected to decrease by about 1.1 to 1.6 percent. The largest change is in acetaldehyde emissions, an increase of 17.1 to 35.7 percent, as acetaldehyde is a partial combustion product of ethanol. 108 These emission estimates do not include the impact of the recent mobile source air toxic standards (72 FR 8428, February 26, 2007). CO also participates in forming ozone, much like VOCs. Generally, CO is 15-50 times less reactive than typical VOC. Still, the reduction in CO emissions is roughly 27-32 times the increase in VOC emissions in the two scenarios. Thus, the projected reduction in CO emissions is important from an ozone perspective. However, as described above, the methodology for projecting the effect of ethanol use on CO emissions is inconsistent with that for exhaust VOC and NO <sup>X</sup> emissions. Thus, comparisons between changes in VOC and CO emissions are particularly uncertain. There will also be some increases in emissions due to ethanol and biodiesel production. Table VIII.B.1-2 shows estimates of annual emissions expected to occur nationwide due to increased production of ethanol. These estimates include a reduction in emissions related to the distribution of the displaced gasoline. The table reflects the use of emissions factors from DOE's GREET model, version 1.7, as well as estimates of ethanol plant emissions obtained from the States. It should be noted that emissions in the base case assume an 80/20 mix of dry mill and wet mill facilities. New plants (and thus, the emission increases) assume 100% dry mill facilities. Table VIII.B.1-2.—Annual Emissions Nationwide From Ethanol Production and Transportation: 2012 [Tons per year] GREET1.7 Base case RFS case EIA case GREET1.7 + State data Base case RFS case EIA case Emissions Increase in emissions Emissions Increase in emissions VOC 8,000 5,000 11,000 14,000 10,000 20,000 NO <sup>X</sup> 17,000 13,000 26,000 18,000 14,000 27,000 CO 49,000 35,000 72,000 56,000 40,000 81,000 PM <sup>10</sup> 21,000 15,000 30,000 12,000 9,000 18,000 SO <sup>X</sup> 27,000 20,000 41,000 42,000 30,000 61,000 As can be seen, the potential increases in emissions from ethanol production and transportation are of the same order of magnitude as those from ethanol use, with the exception of CO emissions. The vast majority of these emissions are related to farming and ethanol production. Both farms and ethanol plants are generally located in ozone attainment areas. Where counties are constructing new ethanol plants, expanding existing plants, or planning construction for future plants, the average increase in VOC and NO <sup>X</sup> emissions from plants alone are about 26 tons/month VOC and 35 tons/month NO <sup>X</sup> using state data (about 17 tons/month VOC and 25 tons/month NO <sup>X</sup> using GREET 1.7 emission factors). Average VOC and NO <sup>X</sup> emissions increase to about 61 tons/month and 83 tons/month, respectively, in the 10% of counties expecting largest increases in ethanol production. For both VOC and NO <sup>X</sup> , emissions estimates are about 35% less when using the GREET 1.7 emission factors. Table VIII.B.1-3 shows estimates of annual emissions expected to occur nationwide due to increased production of biodiesel. These estimates include a reduction in emissions related to the distribution of the displaced diesel fuel. Again, these emissions are generally expected to be in ozone attainment areas. Table VIII.B.1-3.—Annual Emissions Nationwide From Biodiesel Production and Transportation [Tons per year] Pollutant Reference inventory: 30 mill gal biodiesel per year 2012 Emissions inventory: 300 mill gal biodiesel per year VOC 1,400 14,000 NO <sup>X</sup> 1,500 15,000 CO 800 8,000 PM <sup>10</sup> 50 500 SO <sup>X</sup> 250 2,500 2. Sensitivity Analysis The national emission inventories for VOC and NO <sup>X</sup> in 2012 with current fuels are summarized in Table VIII.B.2-1. Here, the emission effects contained in the EPA Predictive Models are assumed to apply to all vehicles, not just Tier 0 vehicles. Also shown are the changes in emissions projected for the two cases for future ethanol volume. Table VIII.B.2-1.—2012 Emissions Nationwide From Gasoline Vehicles and Equipment Under Two Future Ethanol Use Scenarios—Sensitivity Analysis [Tons per year] Pollutant Inventory Reference case Change in inventory in control cases RFS case EIA case VOC 5,834,000 −20,000 −4,000 NO <sup>X</sup> 2,519,000 68,000 106,000 CO 54,315,000 −692,000 −1,975,000 Benzene 175,700 −5,000 −9,400 Formaldehyde 39,600 −1,100 −700 Acetaldehyde 19,500 3,000 6,600 1,3-Butadiene 18,600 −400 −600 The overall VOC and NO <sup>X</sup> emission impacts of the various ethanol use scenarios change to some degree when all motor vehicles are assumed to be sensitive to fuel ethanol content. The increase in VOC emissions turns into a net decrease due to a greater reduction in exhaust VOC emissions from onroad vehicles. However, the increase in NO <sup>X</sup> emissions gets larger, as more vehicles are assumed to be affected by ethanol. Emissions of the four air toxics generally decrease slightly, due to the greater reduction in exhaust VOC emissions. 3. Local and Regional VOC and NO <sup>X</sup> Emission Impacts in July We also estimate the percentage change in VOC, NO <sup>X</sup> , and CO emissions from gasoline fueled motor vehicles and equipment in those areas which actually experienced a significant change in ethanol use. Specifically, we focused on areas where the market share of ethanol blends was projected to change by 50 percent or more. We also focused on summertime emissions, as these are most relevant to ozone formation. Finally, we developed separately estimates for:
(1)RFG areas, including the state of California and the portions of Arizona where their CBG fuel programs apply,
(2)low RVP areas ( *i.e.* , RVP standards less than 9.0 RVP, and
(3)areas with a 9.0 RVP standard. This set of groupings helps to highlight the emissions impact of increased ethanol use in those areas where emission control is most important. Table VIII.B.3-1 presents our primary estimates of the percentage change in VOC, NO <sup>X</sup> , and CO emission inventories for these three types of areas. Note that the analyses here are very similar to those described in Section 5.1 of the RIA, with the exception that Table VIII.B.3-1 below reflects 50 states (instead of 37 eastern states) and excludes diesel emissions. Table VIII.B.3-1.—July 2015 Change in Emissions from Gasoline Vehicles and Equipment in Counties Where Ethanol Use Changed Significantly—Primary Analysis Ethanol use RFS case EIA case RFG Areas Ethanol Use Down Up. VOC 0.8% 2.3%. NO <sup>X</sup> −3.4% 1.6%. CO 6.1% −2.6%. Low RVP Areas Ethanol Use Up Up. VOC 4.2% 4.6%. NO <sup>X</sup> 6.2% 5.7%. CO −12.5% −13.7%. Other Areas (9.0 RVP) Ethanol Use Up Up. VOC 3.6% 4.6%. NO <sup>X</sup> 7.3% 7.0%. CO −6.4% −6.0%. As expected, increased ethanol use tends to increase NO <sup>X</sup> emissions. The increase in low RVP and other areas is greater than in RFG areas, since the RFG in the RFG areas included in this analysis all contained MTBE. Also, increased ethanol use tends to increase VOC emissions, indicating that the increase in non-exhaust VOC emissions exceeds the reduction in exhaust VOC emissions. This effect is muted with RFG due to the absence of an RVP waiver for ethanol blends. We would expect very similar results for 2012. The reader is referred to Chapter 2 of the RIA for discussion of how ethanol levels will change at the state-level. Table VIII.B.3-2 presents the percentage change in VOC, NO <sup>X</sup> , and CO emission inventories under our sensitivity case ( *i.e.* , when we apply the emission effects of the EPA Predictive Models to all motor vehicles). Table VIII.B.3-2.—July 2015 Change in Emissions From Gasoline Vehicles and Equipment in Counties Where Ethanol Use Changed Significantly—Sensitivity Analysis Ethanol use RFS case EIA case RFG Areas Ethanol Use Down Up. VOC −1.0% 1.0%. NO <sup>X</sup> −0.9% 5.6%. CO 7.3% −3.0%. Low RVP Areas Ethanol Use Up Up. VOC 3.4% 3.7%. NO <sup>X</sup> 10.4% 10.8%. CO −15.0% −16.4%. Other Areas (9.0 RVP) Ethanol Use Up Up. VOC 3.0% 3.9%. NO <sup>X</sup> 10.8% 11.0%. CO −9.0% −8.9%. Directionally, the changes in VOC and NO <sup>X</sup> emissions in the various areas are consistent with those from our primary analysis. The main difference is that the increases in VOC emissions are smaller, due to more vehicles experiencing a reduction in exhaust VOC emissions, and the increases in NO <sup>X</sup> emissions are larger. C. Impact on Air Quality We estimate the impact of increased ethanol use on the ambient concentrations of two pollutants: Ozone and PM. Quantitative estimates are made for ozone, while only qualitative estimates can be made currently for ambient PM. These impacts are described below. 1. Impact of Increased Ethanol Use on Ozone We use a metamodeling tool developed at EPA, the ozone response surface metamodel (Ozone RSM), to estimate the effects of the projected changes in emissions from gasoline vehicles and equipment for the RFS and EIA cases. We included the estimated changes in emissions from renewable fuel production and distribution. Because of limitations in the Ozone RSM, we could not easily assign these emissions to the specific counties where the plants are or are expected to be located. Instead, we assigned all of the emissions related to renewable fuel production and distribution to the set of states expected to contain most of the production facilities. The Ozone RSM was created using multiple runs of the Comprehensive Air Quality Model with Extensions (CAM <sup>X</sup> ). Base and proposed control CAM <sup>X</sup> metamodeling was completed for the year 2015 over a modeling domain that includes all or part of 37 Eastern U.S. states, plus the District of Columbia. For more information on the Ozone RSM, please see Chapter 5 of the RIA for this final rule. The Ozone RSM limits the number of geographically distinct changes in VOC and NO <sup>X</sup> emissions which can be simulated. As a result, we could not apply distinct changes in emissions for each county. Therefore, two separate runs were made with different VOC and NO <sup>X</sup> emissions reductions. We then selected the ozone impacts from the various runs which best matched the VOC and NO <sup>X</sup> emission reductions for that county. This models the impact of local emissions reasonably well, but loses some accuracy with respect to ozone transport. No ozone impact was assumed for areas which did not experience a significant change in ethanol use. The predicted ozone impacts of increased ethanol use for those areas where ethanol use is projected to change by more than a 50% market share are summarized in Table VIII.C.1-1. As shown in the Table 5.1-2 of the RIA, national average impacts (based on the 37-state area modeled) which include those areas where no change in ethanol use is occurring are considerably smaller. Table VIII.C.1-1.—Impact on 8-Hour Design Value Equivalent Ozone Levels
(ppb)a Primary analysis RFS case EIA case Sensitivity analysis RFS case EIA case Minimum Change −0.015 0.000 −0.115 0.028 Maximum Change 0.329 0.337 0.624 0.549 Average Change b 0.153 0.181 0.300 0.325 Population-Weighted Change b 0.154 0.183 0.272 0.315 a In comparison to the 80 ppb 8-hour ozone standards. b Only for those areas experiencing a change in ethanol blend market share of at least 50 percent. As can be seen, ozone levels generally increase to a small degree with increased ethanol use. This is likely due to the projected increases in both VOC and NO <sup>X</sup> emissions. Some areas do see a small decrease in ozone levels. In our primary analysis, where exhaust emissions from Tier 1 and later onroad vehicles are assumed to be unaffected by ethanol use, the population-weighted increase in ambient ozone levels in those areas where ethanol use changed significantly is 0.154-0.183 ppb. Since the 8-hour ambient ozone standard is 85 ppb, this increase represents about 0.2 percent of the standard, a very small percentage. In our sensitivity analysis, where exhaust emissions from Tier 1 and later onroad vehicles are assumed to respond to ethanol like Tier 0 vehicles, the population-weighted increase in ambient ozone levels is slightly less than twice as high, or 0.272-0.315 ppb. This increase represents about 0.35 percent of the standard. There are a number of important caveats concerning these estimates. First, the emission effects of adding ethanol to gasoline are based on extremely limited data for recent vehicles and equipment. Second, the Ozone RSM does not account for changes in CO emissions. As shown above, ethanol use should reduce CO emissions significantly, directionally reducing ambient ozone levels in those areas where ozone formation is VOC-limited. (Ozone levels in areas which are NO <sup>X</sup> -limited are less likely to be affected by a change in CO emissions.) The Ozone RSM also does not account for changes in VOC reactivity. With additional ethanol use, the ethanol content of VOC should increase. Ethanol is less reactive than the average VOC. Therefore, this change should also reduce ambient ozone levels in a way not addressed by the Ozone RSM, again in those areas where ozone formation is predominantly VOC-limited. Because of these limitations, anyone interested in the impact of increased ethanol use on ozone in any particular area should utilize more comprehensive dispersion modeling which accounts for these and other important factors. We received several requests in comments on the proposal to quantify the impact of the reduced CO emissions and VOC reactivity on ozone. As discussed in the S&A document, this is not possible without running more sophisticated ambient dispersion models. The impact of CO emissions and VOC reactivity on ozone vary significantly depending on ambient conditions and the relative amount of VOC and NO <sup>X</sup> in the atmosphere. Therefore, general rules of thumb cannot be applied. Moving to health effects, exposure to ozone has been linked to lung function decrements, respiratory symptoms, aggravation of asthma, increased hospital and emergency room visits, increased asthma medication usage, inflammation of the lungs, and a variety of other respiratory effects and cardiovascular effects including premature mortality. Ozone can also adversely affect the agricultural and forestry sectors by decreasing yields of crops and forests. Although the health and welfare impacts of changes in ambient ozone levels are typically quantified in regulatory impact analyses, we do not evaluate them for this analysis. On average, the changes in ambient ozone levels shown above are small and would be even smaller if changes in CO emissions and VOC reactivity were taken into account. The increase in ozone would likely lead to negligible monetized impacts. We therefore do not estimate and monetize ozone health impacts for the changes in renewable use due to the small magnitude of this change, and the uncertainty present in the air quality modeling conducted here, as well as the uncertainty in the underlying emission effects themselves discussed earlier. 2. Particulate Matter Ambient PM can come from two distinct sources. First, PM can be directly emitted into the atmosphere. Second, PM can be formed in the atmosphere from gaseous pollutants. Gasoline-fueled vehicles and equipment contribute to ambient PM concentrations in both ways. As described above, we are not currently able to predict the impact of fuel quality on direct PM emissions from gasoline-fueled vehicles or equipment. Therefore, we are unable at this time to project the effect that increased ethanol use will have on levels of directly emitted PM in the atmosphere. PM can also be formed in the atmosphere (termed secondary PM here) from several gaseous pollutants emitted by gasoline-fueled vehicles and equipment. Sulfur dioxide emissions contribute to ambient sulfate PM. NO <sup>X</sup> emissions contribute to ambient nitrate PM. VOC emissions contribute to ambient organic PM. Increased ethanol use is not expected to change gasoline sulfur levels, so emissions of sulfur dioxide and any resultant ambient concentrations of sulfate PM are not expected to change. Increased ethanol use is expected to increase NO <sup>X</sup> emissions, so the possibility exists that ambient nitrate PM levels could increase. Increased ethanol is generally expected to increase total VOC emissions, which could also impact the formation of secondary organic PM. However, while non-exhaust VOC emissions are expected to increase, exhaust VOC emissions are expected to decrease. Generally, the higher the molecular weight of the specific VOC emitted, the greater the likelihood it will form PM in the atmosphere. Non-exhaust VOC is predominantly low in molecular weight, as much of it is due to fuel evaporating. Thus, emissions of VOCs likely to form PM in the atmosphere are likely decreasing with ethanol use. The formation of secondary organic PM is very complex, due in part to the wide variety of VOCs emitted into the atmosphere. The degree to which a specific gaseous VOC reacts to form PM in the atmosphere depends on the types of reactions that specific VOC undergoes and the products of those reactions. Both of these factors depend on other pollutants present, such as the hydroxyl radical, ozone, NO <sup>X</sup> and other reactive compounds. The relative mass of secondary PM formed per mass of gaseous VOC emitted can also depend on the total concentration of gaseous VOC and organic PM in the atmosphere. Most of the secondary organic PM exists in a continually changing equilibrium between the gaseous and PM phases. Both the rates of these reactions and the gaseous-PM equilibria depend on temperature, so seasonal differences can be expected. Recent smog chamber studies have indicated that gaseous aromatic VOCs can form secondary PM under certain conditions. These compounds comprise a greater fraction of exhaust VOC emissions than non-exhaust VOC emissions, as non-exhaust VOC emissions are dominated by VOCs with relatively high vapor pressures. Aromatic VOCs tend to have lower vapor pressures. As increased ethanol use is expected to reduce exhaust VOC emissions, emissions of aromatic VOCs should also decrease. In addition, refiners are expected to reduce the aromatic content of gasoline by 5 volume percentage points as ethanol is blended into gasoline. Emissions of aromatic VOCs should decrease with lower concentrations of aromatics in gasoline. Thus, emissions of gaseous aromatic VOCs could decrease for both reasons. Overall, we expect that the decrease in secondary organic PM is likely to exceed the increase in secondary nitrate PM. In 1999, NO <sup>X</sup> emissions from gasoline-fueled vehicles and equipment comprised about 20% of national NO <sup>X</sup> emissions from all sources. In contrast, gasoline-fueled vehicles and equipment comprised over 60% of all national gaseous aromatic VOC emissions. The percentage increase in national NO <sup>X</sup> emissions due to increased ethanol use should be smaller than the percentage decrease in national emissions of gaseous aromatics. Finally, in most urban areas, ambient levels of secondary organic PM exceed those of secondary nitrate PM. Thus, directionally, we expect a net reduction in ambient PM levels due to increased ethanol use. However, we are unable to quantify this reduction at this time. EPA currently utilizes the CMAQ model to predict ambient levels of PM as a function of gaseous and PM emissions. This model includes mechanisms to predict the formation of nitrate PM from NO <sup>X</sup> emissions. However, it does not currently include any mechanisms addressing the formation of secondary organic PM. EPA is currently developing a model of secondary organic PM from gaseous toluene emissions. We plan to incorporate this mechanism into the CMAQ model in 2007. The impact of other aromatic compounds will be added as further research clarifies their role in secondary organic PM formation. Therefore, we expect to be able to quantitatively estimate the impact of decreased toluene emissions and increased NO <sup>X</sup> emissions due to increased ethanol use as part of future analyses of U.S. fuel requirements required by the Act. IX. Impacts on Fossil Fuel Consumption and Related Implications Renewable fuels have been of significant interest for many years due to their potential to displace fossil fuels, which have often been targeted as primary contributors to emissions of greenhouse gases such as carbon dioxide, and national energy concerns primarily due to an increasing dependence on foreign sources of petroleum. In the Notice of Proposed Rulemaking, we provided a preliminary assessment of the greenhouse gas emission and energy impacts of renewable fuel and an initial assessment of the economic value of renewable fuel displacing petroleum-based fuels. We also indicated that we would be updating an analysis of energy security impacts that had been prepared by analysts at the Oak Ridge National Laboratory
(ORNL)of the Department of Energy. We present some discussion of that analysis here. We also performed a full lifecycle or well-to-wheel analysis for this final rule to estimate the GHG and fossil energy reductions from replacing petroleum based fuels with renewable fuels. Argonne National Laboratory's
(ANL)GREET 109 model was utilized for this lifecycle analysis. Table IX-1 summarizes this model's estimated impact that increases in the use of renewable fuels are projected to have on GHG emissions and fossil fuel consumption for the two renewable fuel volume scenarios considered in this final rulemaking relative to the reference case. As described later in this section, the results in Table IX-1 are based on a number of input assumptions including coal being used as process fuel in 14% of ethanol facilities. 109 Greenhouse gases, Regulated Emissions, and Energy use in Transportation. As noted in Section III, although we have chosen to base our lifecycle analyses on Argonne National Laboratory's GREET model there are a variety of other lifecycle models and analyses available. The choice of model inputs and assumptions all have a bearing on the results of lifecycle analyses, and many of these assumptions remain the subject of debate among researchers. Lifecycle analyses must also contend with the fact that the inputs and assumptions generally represent industry-wide averages even though energy consumed and emissions generated can vary widely from one facility or process to another. There currently exists no organized, comprehensive dialogue among stakeholders about the appropriate tools and assumptions behind any lifecycle analyses. We will be initiating more comprehensive discussions about lifecycle analyses with stakeholders in the near future. Table IX-1.—GREET Model Lifecycle Reductions From Increased Renewable Fuel Use Relative to the 2012 Reference Case RFS case Reduction % of trans. sector EIA case Reduction % of trans. sector Fossil Energy
(QBtu)0.15 0.48 0.27 0.85 Petroleum Energy
(Bgal)2.0 0.82 3.9 1.60 GHG Emissions (MMT CO <sup>2</sup> -eq.) 8.0 0.36 13.1 0.59 CO2 Emissions (MMT CO <sup>2</sup> ) 11.0 0.52 19.5 0.93 We used the petroleum energy reductions shown in Table IX-1 to determine implications on imports of petroleum products. Our analysis found that calculated petroleum energy reductions come almost entirely from imports of finished products in this 2012 case and amount to the equivalent of 123,000 barrels of transportation fuel under the RFS case and 240,000 barrels of transportation fuel for the EIA case. Another effect of increased use of renewable fuels in the U.S. is that it diversifies the energy sources in making transportation fuel. Diverse sources of fuel energy reduce both financial and strategic risks associated with a potential disruption in supply or a spike in cost of a particular energy source. This reduction in risks is a measure of improved energy security. The ORNL report used an “oil premium” approach to identify those energy-security related impacts which are not reflected in the market price of oil, and which are expected to change in response to an incremental change in the level of U.S. oil imports. The following sections provide a more complete description of our analyses of the GHG emissions, fossil fuel, oil imports, and energy security impacts of this final rule. A. Impacts on Lifecycle GHG Emissions and Fossil Energy Use Although the use of renewable fuels in the transportation sector directly displaces some petroleum consumed as motor vehicle fuel, this displacement of petroleum is in fact only one aspect of the overall impact of renewable fuels on fossil fuel use. Fossil fuels are also used in producing and transporting renewable feedstocks such as plants or animal byproducts, in converting the renewable feedstocks into renewable fuel, and in transporting and blending the renewable fuels for consumption as motor vehicle fuel. To estimate the true impacts of increases in renewable fuels on fossil fuel use, modelers attempt to take many or all these steps into account. Similarly, energy is used and GHGs emitted in the pumping of oil, transporting the oil to the refinery, refining the crude oil into finished transportation fuel, transporting the refined gasoline or diesel fuel to the consumer and then burning the fuel in the vehicle. Such analyses are termed lifecycle or well-to-wheels analyses. We performed a full lifecycle analysis as part of this final rulemaking to determine the GHG and fossil energy reductions from the increased use of renewable fuels. This lifecycle assessment approach and rationale were highlighted in the proposal. Comments received focused mainly on improving the process, for example the choice of lifecycle model used and initiating a stakeholder dialogue to build consensus around the assumptions and approach. In general comments were supportive of using a full lifecycle assessment approach, but differed on the appropriate model and associated assumptions EPA should use in its analysis. 1. Time Frame and Volumes Considered The results presented in this analysis represent a snapshot in time. They represent annual GHG and fossil fuel savings in the year considered, in this case 2012. Consistent with the emissions modeling described in Section VII, our analysis of the GHG and fossil fuel consumption impacts of renewable fuel use was conducted using three volume scenarios. The first scenario was the same reference case used elsewhere in this final rulemaking. The reference case scenario provided the point of comparison for the other two scenarios. The other two renewable fuel scenarios for 2012 represented the RFS program requirements and the volume projected by EIA. In both the RFS and EIA scenarios, we assumed that the biodiesel production volume would be 0.303 billion gallons based on EIA AEO2006 projections. Furthermore, for both scenarios we assume that 250 million gallons of ethanol that qualify for cellulosic biomass ethanol credit will be produced in 2012 from corn using biomass as the process energy source. The remaining renewable fuel volumes in each scenario would be ethanol made from corn and imports. The import volume is based on EIA's projections for the percent of total ethanol volume supplied by imports in 2012. The total volumes for all three scenarios are shown in Table II.A.1-1. For the purposes of calculating this difference or the amount of conventional fuel no longer consumed—that is, displaced—as a result of the use of the replacement renewable fuel, we assumed the ethanol volumes shown in Table II.A.1-1 are 5% denatured. The ethanol volumes were adjusted down to represent pure (100%) ethanol, biodiesel volumes were not adjusted. The adjusted volumes were then converted to total Btu using the appropriate volumetric energy content values (76,000 Btu/gal for ethanol, 115,000 Btu/gal for gasoline, 118,000 Btu/gal for biodiesel, and 130,000 Btu/gal for diesel fuel). We make the assumption that vehicle energy efficiency will not be affected by the presence of renewable fuels (i.e., efficiency of combusting one Btu of ethanol is equal to the efficiency of combusting one Btu of gasoline). This lifecycle analysis is conducted without any regard to the geographic attributes of where emissions or energy use occurs; the model represents global reductions in GHG emissions and energy use, not just those occurring in the U.S. For example, under a full lifecycle assessment approach, the savings associated with reducing overseas crude oil extraction and refining are included, as are the international emissions associated with producing imported ethanol. There were two exceptions to this, both dealing with secondary impacts that may result internationally due to the expanded use of renewable fuels within the United States. The first exception is the emissions associated with international land use change. Due to decreasing corn exports some changes to international land use may occur, for example, as more crops are planted in other regions to compensate for the decrease in crop exports from the U.S. While the emissions associated with domestic land use change are well understood and are included in our lifecycle analysis, we did not include the potential impact on international land use and any emissions that might directly result. Our currently modeling capability does not allow us to assess what international land use changes would occur or how these changes would affect greenhouse gas emissions. For example, we would need to know how international cropping patterns would change as well as farming inputs and practices that might affect emissions assessment. The second case where we have not quantified the international impacts results from any reduction in world oil prices would tend to result from decreased demand in the U.S. as renewable fuels replace oil. It is commonly presumed in economic analyses that all else being equal quantity demanded of a valuable good (i.e., oil) will increase as price decreases. A world wide reduction of oil price would tend to reduce the cost of producing transportation fuel which in turn would tend to reduce the price consumers internationally would have to pay for this fuel. To the extent fuel prices are decreased, demand and consumption would tend to increase; this impact of reduced cost of driving is sometimes referred to as a “rebound effect.” Such a greater consumption internationally would presumably result in an increase in greenhouse gas emissions as consumers in the rest of the world drive more. These increased emissions would in part offset the emission impacts otherwise described in this preamble. While such international impacts of U.S. actions are important to understand, we have not have fully considered and quantified the international rebound effects of this renewable fuel standard. Nevertheless, such impacts remain an important consideration for future analysis. 2. GREET Model As in the analyses for the proposal, for this final rulemaking we used the GREET fuel-cycle model. GREET has been under development for several years and has undergone extensive peer review through multiple updates. Of the available sources of information on lifecycle analyses of energy consumed and emissions generated, we believe that GREET offers the most comprehensive treatment of the transportation sector. For this final rule, we used an updated version of the GREET model 110 , with a few modifications to its input assumptions. These changes since the NPRM are described below. 110 GREET version 1.7, released November 10, 2006. The two main comments we received on our lifecycle modeling were that we should initiate a public dialogue on lifecycle analyses, models and assumptions, and that our sole reliance on the GREET model should be avoided, given other models are available. We have begun a public dialogue in that we identify the assumptions in the GREET model that were examined and modified for this final rulemaking. Furthermore, we will be initiating more comprehensive discussions about lifecycle analysis with stakeholders which could lead to an increased use of lifecycle analysis in future actions. In terms of our sole reliance on the GREET model, several other models have been developed for conducting renewable fuels lifecycle analysis. For example, researchers at the Energy and Resources Group
(ERG)of the University of California Berkeley have developed the ERG Biofuel Analysis Meta-Model (EBAMM) and Mark Delucchi at the Institute of Transportation Studies of the University of California Davis has developed the Lifecycle Emissions Model (LEM). Other non-fuel specific lifecycle modeling tools could also be used to perform renewable fuel lifecycle analysis. Several studies have been released recently making use of these other models and showing different results than we find in the analysis done for this rule. For example, whereas GREET estimates a net GHG reduction of about 22% for corn ethanol compared to gasoline, the previously cited works by Farrell et al. utilizing the EBAMM show around a 13% reduction. The main difference in results is not due to the model used but assumptions on scope and input data. For example, most studies focus on average or current ethanol production which uses a current mix of wet and dry mill ethanol production and use of coal and natural gas as process energy. In contrast, for this rulemaking we consider future increases in renewable fuel production so we focus on new production capacity which will rely more heavily on more efficient dry mill production than the current mix of wet and dry mill capacities. Other studies also typically base ethanol and farm energy use on historic data while we are assuming future capacity increases will use a state of the art dry milling plant and most current farming energy use data. Varying assumptions concerning how land use change impact CO <sup>2</sup> emissions and agriculture related GHG emissions could also have an impact on overall results. Other studies also differ in the environmental flows considered. For example, GREET uses the internationally accepted set of greenhouse gases while Delucchi uses additional types of greenhouse gases. We have not had an opportunity to develop comparable analyses of the GHG and energy impacts of this rule using these other models. However, as discussed in chapters 6.1.1 and 6.2.3 of the RIA, we believe the scope of the GREET model and the assumptions we have used in running the model tend toward the middle of the range. Therefore we believe these results provide a reasonable assessment of the energy and GHG impacts of the expanded use of renewable fuels. a. Renewable Fuel Pathways Considered The feedstocks and processes used to model renewable fuel production were those which our analysis in Chapter 1 of the RIA shows will primarily be used through 2012. However, other pathways for producing renewable fuels may become popular such as producing cellulosic biomass ethanol from municipal solid waste as well as different process for the feedstocks considered, like gasification of switchgrass and production of “renewable” diesel fuel through hydrotreating vegetable oils. Furthermore, the lifecycle analysis used for this rulemaking is based on averages of the different renewable fuels modeled. For example, the GHG emission and fossil energy savings associated with increased use of corn ethanol are calculated based on a mix of corn wet and dry milling, assuming a certain projected mix of each process. While this method may not exactly represent the reductions associated with a given gallon of renewable fuel, it is accurate for the purpose of this analysis which is to determine the impact of the total increased volume of renewable fuels used. We recognize that different feedstocks and processes will each have unique characteristics when it comes to lifecycle GHG emissions and energy use. However, we understand that other feedstocks and processes as well as differences in other parts of the renewable fuel lifecycle will impact the savings associated with their use and this is the focus of ongoing work at the agency. b. Modifications to GREET Since the analysis done for the NPRM, we have updated the GREET model with the following changes: —Included CO <sup>2</sup> emissions from corn farming lime use. —Updated the corn farming fertilizer use inputs. —Added cellulosic biomass ethanol production from corn stover and forest waste. —Modeled biomass as a process fuel source in corn ethanol dry milling. In addition to the changes listed above we also examined and updated other GREET input assumptions for corn ethanol and biodiesel production. We also examined several other GREET input values, but determined that the default GREET values should not be changed for a variety of reasons. These included, corn and ethanol transport distances and modes and byproduct allocation methods. Our investigation of these other GREET input values are discussed more fully in Chapter 6 of the RIA. The current GREET default factors for these other inputs were included in the analysis for this final rule. We did not investigate the input values associated with the production of petroleum-based gasoline or diesel fuel in the GREET model for this final rule. However, the refinery modeling discussed in Section VII provides some additional information on the process energy requirements associated with the production of gasoline and diesel under a renewable fuels mandate. We will use information from this refinery modeling in future analysis to determine if any GREET input values should be changed. A summary of the GREET input values we investigated and modified for the final rule analysis is given below. *Corn Farming Energy Use:* Corn farming energy use was updated based on the most recent USDA Agricultural Resource Management Survey
(ARMS)data. *CO* 2 *from Land Use Change:* The GREET model has a default factor for CO <sup>2</sup> from land use change that was included in the NPRM analysis. This factor was updated based on the results of the agricultural sector modeling outlined in Section X. The CO <sup>2</sup> emissions from land use change used in the final rulemaking represents approximately 1% of total corn ethanol lifecycle GHG emissions. However, this value could be more significant if increased amounts of renewable fuels are used in the transportation sector. The issue of CO <sup>2</sup> emissions from land use change associated with converting forest or Conservation Reserve Program
(CRP)land into crop production for use in producing renewable fuels is an important factor to consider when determining the overall sustainability of renewable fuel use. While the analysis described above is indicating that the volumes of renewable fuel analyzed in this rulemaking will not cause a significant change in land use, this is an area we will continue to research for any future analysis. *Corn Ethanol Wet-Mill Versus Dry Mill Plants:* For this analysis, we expect most new ethanol plants will be dry mill operations. That has been the trend in the last few years as the demand for ethanol has grown, and our analysis of ethanol plants under construction and planned for the near future has verified this. Our analysis of production plans, as outlined in Section VI, indicates that essentially all new ethanol production will be from dry mill plants (99%). *Corn Ethanol Dry Mill Plant Energy Use and Fuel Mix:* Our review of plants under construction and those planned for the near future as outlined in Section VI, indicates that coal will be used as process fuel for approximately 14% of the new under construction and planned ethanol production volume capacity. The energy use at a dry mill plant using natural gas was based on the model developed by USDA and modified by EPA for use in the cost analysis of this rulemaking described in Section VII. For this analysis, we assumed that a coal plant would require 15% 111 more electricity demand due to coal handling and have a 13% increase in thermal demand for steam dryers as compared to the natural gas fueled plant. We also considered a case where a corn ethanol plant utilized biomass as a fuel source. For this case we assumed the same amount of fuel and purchased electricity energy per gallon as a coal powered plant. This assumption is based on the biomass plant having more fuel handling than a natural gas plant and producing steam for DDGS drying. 111 Baseline Energy Consumption Estimates for Natural Gas and Coal-based Ethanol Plants—The Potential Impact of Combined Heat and Power (CHP), Prepared for: U.S. Environmental Protection Agency Combined Heat & Power Partnership, Prepared by: Energy and Environmental Analysis, Inc., July 2006. *Corn Ethanol Dry Mill Plant Production Yield:* Modern ethanol plants are now able to produce more than 2.7 gallons of ethanol per bushel of corn compared with less than 2.4 gallons of ethanol per bushel of corn in 1980. The development of new enzymes continues to increase the potential ethanol yield. We used a value of 2.71 112 gal/bu in our analysis, which may underestimate actual future yields. For additional information on our yield analysis, see the cost modeling of corn ethanol discussed in Section VII. 112 All yield values presented represent pure ethanol production ( *i.e.* no denaturant). *Corn Ethanol Co-Products:* We based the amount of DDGS produced by an ethanol dry mill plant on the USDA model used in the cost analysis work of this rulemaking, described in Section VII. Based on the agricultural sector modeling outlined in Section X, we assumed that one ton of DDGS displaces 0.5 tons of corn and 0.5 tons of soybean meal. We also assume for corn ethanol wet milling that one ton of corn gluten meal substitutes for one ton of soybean meal, one ton of corn gluten feed substitutes for 0.5 tons of corn, and one ton of corn oil substitutes for one ton of soybean oil. *Biodiesel Production:* Two scenarios for biodiesel production were considered, one utilizing soybean oil as a feedstock and one using yellow grease. For the soybean oil scenario, the energy use and inputs for the biodiesel production process were based on a model developed by NREL and used by EPA in the cost modeling of soybean oil biodiesel, as discussed in Section VII. The GREET model does not have a specific case of biodiesel production from yellow grease. Therefore, as a surrogate we used the soybean oil based model with several adjustments. For the yellow grease case, we did not include soybean agriculture emissions or energy use. Soybean crushing was still included as a surrogate for yellow grease processing (purification, water removal, etc.). Also, due to additional processing requirements, the energy use associated with producing biodiesel from yellow grease is higher than for soybean oil biodiesel production. As per the cost modeling of yellow grease biodiesel discussed in Section VII, the energy use for yellow grease biodiesel production was assumed to be 1.72 times the energy used for soybean oil biodiesel. *Biodiesel Transportation:* Biodiesel transportation was based on the distribution infrastructure modeling for this rulemaking which indicates pipelines are not currently used to transport biodiesel and are not projected to play a role in biodiesel transport in the future time frame considered. Therefore, GREET default factors for biodiesel transportation from plant to terminal were modified to remove pipeline transport. c. Sensitivity Analysis As mentioned above, the results of lifecycle analysis are highly dependent on the input data assumptions used. Section IX.A.1.b outlined changes made to the GREET model inputs to better represent the scope and purpose of our analysis for this rulemaking. However, we also performed several sensitivity analyses on some key assumptions to see how varying them would impact overall results. We performed a sensitivity analysis on expanding the lifecycle fuel production system boundaries to include farm equipment production (e.g., emissions and energy use associated with producing steel, rubber, etc. used to make farming equipment). It was found that including farm equipment production energy use and emissions increases ethanol lifecycle energy use and GHG emissions by approximately 1 percent. Therefore, the lifecycle results are not changed significantly due to this expansion of system boundaries. We also performed a sensitivity analysis on the allocation method used in ethanol production. A number of by-products are made during the production of ethanol. In lifecycle analyses, the energy consumed and emissions generated by an ethanol plant must be allocated not only to ethanol, but also to each of the by-products. There are a number of methods that can be used to estimate by-product allocations. The displacement method for by-product allocation, described in Section 6.1.2.10 of the RIA, is the default for the GREET model and is the method used by EPA. However, we evaluated another method, the process energy approach, to determine the impact this assumption has on the overall results of the analysis. Use of the process energy based allocation method reduces ethanol lifecycle energy use and GHG emissions by approximately 30 percent compared to the displacement allocation approach. This indicates that ethanol lifecycle analysis results are extremely sensitive to the choice of allocation method used. (See the RIA, Chapter 6 for more information on these two by-product allocation methods) The displacement allocation method is the method supported by international lifecycle assessment standards 113 and therefore EPA feels that it is the most accurate and preferred method to use. This does however highlight the sensitivity of lifecycle analysis results to choice of input parameters and assumptions. 113 ISO 14044:2006(E), “Environmental Management—Life Cycle Assessment—Requirements and Guidelines”, International Organization for Standardization (ISO), First edition, 2006-07-01, Switzerland. 3. Displacement Indexes
(DI)The displacement index
(DI)represents the percent reduction in GHG emissions or fossil fuel energy brought about by the use of a renewable fuel in comparison to the conventional gasoline or diesel that the renewable fuel replaces. The formula for calculating the displacement index depends on which fuel is being displaced (i.e. gasoline or diesel), and which endpoint is of interest (e.g. petroleum energy, GHG). For instance, when investigating the CO <sup>2</sup> impacts of ethanol used in gasoline, the displacement index is calculated as follows: ER01MY07.058 The units of g/Btu ensure that the comparison between the renewable fuel and the conventional fuel is made on a common basis, and that differences in the volumetric energy content of the fuels is taken into account. The denominator includes the CO <sup>2</sup> emitted through combustion of the gasoline itself in addition to all the CO <sup>2</sup> emitted during its manufacturer and distribution. The numerator, in contrast, includes only the CO <sup>2</sup> emitted during the manufacturer and distribution of ethanol, not the CO <sup>2</sup> emitted during combustion of the ethanol. The combustion of biomass-based fuels, such as ethanol from corn and woody crops, generates CO <sup>2</sup> . However, in the long run the CO <sup>2</sup> emitted from biomass-based fuels combustion does not increase atmospheric CO <sup>2</sup> concentrations, assuming the biogenic carbon emitted is offset by the uptake of CO <sup>2</sup> resulting from the growth of new biomass. Thus ethanol's carbon can be thought of as cycling from the environment into the plant material used to make ethanol and, upon combustion of the ethanol, back into the environment from which it came. As a result, CO <sup>2</sup> emissions from biomass-based fuels combustion are not included in their lifecycle emissions results and are not used in the CO <sup>2</sup> displacement index calculations shown above. Net carbon fluxes from changes in biogenic carbon reservoirs in wooded or crop lands are accounted for separately in the GREET model. Using GREET, we calculated the lifecycle values for energy consumed and GHGs produced for corn-ethanol, cellulosic ethanol, and soybean-based biodiesel. These values were in turn used to calculate the displacement indexes. The results are shown in Table IX.A.3-1. Details of these calculations can be found in Chapter 6 of the RIA. Table IX.A.3-1.—Displacement Indexes Derived From GREET [In percent] Corn ethanol Corn ethanol (biomass fuel) Cellulosic ethanol Imported ethanol Biodiesel DI <sup>Fossil Fuel</sup> 39.4 76.3 92.7 69.0 61.5 DI <sup>Petroleum</sup> 91.8 92.0 91.7 92.0 91.2 DI <sup>GHG</sup> 21.8 54.1 90.9 56.0 67.7 DI <sup>CO2</sup> 40.3 72.3 100.1 71.0 69.8 The displacement indexes in this table represent the impact of replacing a Btu of gasoline or diesel with a Btu of renewable fuel. Thus, for instance, for every Btu of gasoline which is replaced by corn ethanol, the total lifecycle GHG emissions that would have been produced from that Btu of gasoline would be reduced by 21.8 percent. For every Btu of diesel which is replaced by biodiesel, the total lifecycle petroleum energy that would have been consumed as a result of burning that Btu of diesel fuel would be reduced by 91.2 percent. Consistent with the cost modeling done for this rule, for the 2012 cases we assume the “cellulosic” ethanol volume is actually produced from corn utilizing a biomass fuel source at the ethanol production plant. The displacement index for that fuel as shown in Table IX.A.3-1 is used in the calculation of reductions. We have included the column for cellulosic ethanol for comparison, indicating that a move toward cellulosic ethanol will not displace petroleum much differently than other renewable fuels but will have a positive impact on GHG emissions reductions. For imported ethanol, it is more difficult to estimate the lifecycle energy and GHG displacement indexes since we know much less about how the crops used to make the ethanol are grown and what energy is used in the ethanol production facility. While not exclusively, we anticipate much imported ethanol to be primarily sugarcane based ethanol. The GHG emissions when producing sugarcane ethanol differs from corn ethanol in that the GHG emissions from growing sugarcane is likely different than for growing a equivalent amount of corn to make a gallon of ethanol. Also, the process of turning sugar into ethanol is easier than when starting with starch and therefore less energy intensive (which typically translates into lower GHG). Importantly, we understand that at least some of the ethanol produced in Brazil uses the bagasse from the sugarcane itself as a process fuel source. We know from our analysis that using a biomass source for process energy greatly improves the GHG benefit of the renewable fuel. These factors would result in sugarcane ethanol having a greater GHG benefit per gallon than corn ethanol, certainly where natural gas or coal is the typical process fuel source used. Conversely, sugarcane ethanol production does not result in a co-product such as distillers grain as in the case of corn ethanol. In our analyses, accounting for co-products significantly improved the GHG displacement index for corn ethanol. Furthermore, there would be additional transportation emissions associated with transporting the imported ethanol to the U.S. as compared to domestically produced ethanol. Developing a technically rigorous lifecycle estimate for energy needs and GHG impacts for imported ethanol is not a simple task and was not available in the timeframe of this rulemaking. Considering all of the differences between imported and domestic ethanol, for this rulemaking, we assumed imported ethanol would be predominately from sugarcane and have estimated DI's approximately mid-way between the DI's for corn ethanol and DI's for cellulosic ethanol. We are continuing to develop a better understanding of the lifecycle energy and GHG impacts of producing ethanol from sugarcane and other likely feedstock sources of imported ethanol for any future analysis. 4. Impacts of Increased Renewable Fuel Use We used the methodology described above to evaluate impacts of increased use of renewable fuels on consumption of petroleum and fossil fuels and also on emissions of CO <sup>2</sup> and GHGs. This section describes our results. a. Greenhouse Gases and Carbon Dioxide We estimated the reduction associated with the increased use of renewable fuels on lifecycle emissions of CO <sup>2</sup> and total GHG. Since total GHG emission reductions are lower than CO <sup>2</sup> reductions, this indicates that lifecycle emissions of CH <sup>4</sup> and N <sup>2</sup> O are higher for renewable fuels than for the conventional fuels replaced. These values are then compared to the U.S. transportation sector emissions to get a percent reduction. The estimates for the 2012 cases are presented in Table IX.A.4.a-1. Table IX.A.4.A-1.—Estimated CO <sup>2</sup> and GHG Emission Impacts of Increased Use of Renewable Fuels in the Transportation Sector in 2012, Relative to the 2012 Reference Case RFS case EIA case CO <sup>2</sup> Reduction (million metric tons CO <sup>2</sup> ) 11.0 19.5 Percent reduction in Transportation Sector CO Emissions 0.52 0.93 GHG Reduction (million metric tons CO <sup>2</sup> -eq.) 8.0 13.1 Percent reduction in Transportation Sector GHG Emissions 0.36 0.59 b. Fossil Fuel and Petroleum We estimated the reduction associated with the increased use of renewable fuels on lifecycle fossil fuels and petroleum. These values are then compared to the U.S. transportation sector emissions to get a percent reduction. The estimates for the 2012 cases are presented in Table IX.A.4.b-1. Table IX.A.4.B-1.—Estimated Fossil Fuel and Petroleum Impacts of Increased Use of Renewable Fuels in the Transportation Sector in 2012, Relative to the 2012 Reference Case RFS case EIA case Fossil Fuel Reduction (quadrillion Btu) 0.15 0.27 Percent reduction in Transportation Sector Fossil Fuel Use 0.48 0.85 Petroleum Energy Reduction (billion gal.) 2.0 3.9 Percent reduction in Transportation Sector Petroleum Use 0.82 1.60 B. Implications of Reduced Imports of Petroleum Products In the proposal, we estimated the impact of expanded renewable fuel use on the importation of oil and finished transportation fuel. No comments were received suggesting alternative methodologies should be used. Therefore, we have incorporated that calculation in this final rule without change. In 2005, the United States imported almost 60 percent of the oil it consumed. This compares to just over 35 percent of oil from imports in 1975. 114 Transportation accounts for 70 percent of the U.S. oil consumption. It is clear that oil imports have a significant impact on the U.S. economy. Expanded production of renewable fuel is expected to contribute to energy diversification and the development of domestic sources of energy. We consider whether the RFS will reduce U.S. dependence on imported oil by calculating avoided expenditures on petroleum imports. Note that we do not calculate whether this reduction is on the net, socially beneficial, which would depend on the scarcity value of domestically produced ethanol versus that of imported petroleum products. However, the next section does discuss some of the energy security implications unique to petroleum imports. 114 Davis, Stacy C.; Diegel, Susan W., Transportation Energy Data Book: 25th Edition, Oak Ridge National Laboratory, U.S. Department of Energy, ORNL-6974, 2006. To assess the impact of the RFS program on petroleum imports, we estimate the fraction of domestic consumption derived from foreign sources using results from the AEO 2006. We compared the levels and mix of imports in the AEO reference case with those in the low macroeconomic growth case and high oil price case. In Section 6.4.1 of the RIA we describe in greater detail how fuel producers may change their levels and mix of imports in response to a decrease in fuel demand. For the purposes of this rulemaking, we show values for the low macroeconomic growth comparison, where import reductions come almost entirely from imports of finished products as shown below in Table IX.B-1. The reductions in imports are compared to the AEO projected levels of net petroleum imports. The range of reductions in net petroleum imports are estimated to be between 0.9 to 1.7 percent, as shown in Table IX.B-1. Table IX.B-1.—Net Reductions in Imports in 2012 RFS case EIA case Reduction in finished products* (barrels per day) 123,000 240,000 Percent reduction** 0.89% 1.73% * Net reductions relative to 2012 reference case. ** Compared to AEO 2006 projections for 2012 reference case. We also calculate the change in expenditures in both petroleum and ethanol imports and compare these with the U.S. trade position measured as U.S. net exports of all goods and services economy-wide. The decreased expenditures were calculated by multiplying the changes in gasoline, diesel, and ethanol imports by the respective AEO 2006 wholesale gasoline, distillate, and ethanol price forecasts for the specific analysis years. In Table IX.B-2, the net expenditures in reduced petroleum imports, increased ethanol imports, and decreased corn exports are compared to the total value of U.S. net exports of goods and services for the whole economy for 2012. Relative to the 2012 projection, the avoided expenditures due to the RFS would represent 0.4 to 0.7% of economy-wide net exports. Table IX.B-2.—Avoided Import Expenditures ($2004 Billion) Cases AEO total net exports Expenditures on petroleum imports Expenditures on ethanol imports Decreased corn exports Net expenditures on imports Percent of total net exports RFS Case −$383 (year 2012) −$2.6 +$0.7 +$0.6 −$1.4 0.4% EIA Case −$5.1 +$1.0 +$1.3 −$2.8 0.7% C. Energy Security Implications of Increases in Renewable Fuels One of the effects of increased use of renewable fuels in the U.S. from the RFS is that it diversifies the energy sources in making transportation fuel. A potential disruption in supply reflected in the price volatility of a particular energy source carries with it both financial as well as strategic risks. These risks can be reduced to the extent that diverse sources of fuel energy reduce the dependence on any one source. This reduction in risks is a measure of improved energy security. At the time of the proposal, EPA stated that an analysis would be completed and estimates provided in support of this rule. In order to understand the energy security implications of the RFS, EPA has worked with Oak Ridge National Laboratory (ORNL), which has developed approaches for evaluating the social costs and energy security implications of oil use. In a new study produced for the RFS, entitled *“The Energy Security Benefits of Reduced Oil Use,* 2006-2015,” ORNL has updated and applied the method used in the 1997 report *“Oil Imports: An Assessment of Benefits and Costs”* , by Leiby, Jones, Curlee and Lee. 115 116 While the 1997 report including a description of methodology and results at that time has been used or cited on a number of occasions, this updated analysis and results have not been available for full public consideration. Since energy security will be a key consideration in future actions aimed at reducing our dependence on oil, it is important to assure estimates of energy security impacts have been thoroughly examined in a full and open public forum. Since the updated analysis was only recently available, such a thorough analysis has not been possible. Therefore, EPA has decided to consider this update as a draft report, include it as part of the record of this rulemaking and invite further public analysis and consideration of both this particular draft report but also other perspectives on how to best quantify energy security benefits. To facilitate that additional consideration, we highlight below some of the key aspects of this particular draft analysis. 115 Leiby, Paul N., Donald W. Jones, T. Randall Curlee, and Russell Lee, Oil Imports: An Assessment of Benefits and Costs, ORNL-6851, Oak Ridge National Laboratory, November, 1997. 116 The 1997 ORNL paper was cited and its results used in DOT/NHTSA's rules establishing CAFE standards for 2008 through 2011 model year light trucks. See DOT/NHTSA, Final Regulatory Impacts Analysis: Corporate Average Fuel Economy and CAFE Reform MY 2008-2011, March 2006. The approach developed by ORNL estimates the incremental benefits to society, in dollars per barrel, of reducing U.S. oil imports, called “oil premium.” Since the 1997 publication of this report, changes in oil market conditions, both current and projected, suggest that the magnitude of the oil premium has changed. Significant driving factors that have been revised include: Oil prices, current and anticipated levels of OPEC production, U.S. import levels, the estimated responsiveness of regional oil supplies and demands to price, and the likelihood of oil supply disruptions. For this analysis, oil prices from the EIA's AEO 2006 were used. Using the “oil premium” approach, estimates of benefits of improved energy security from reduced U.S. oil imports from increased use of renewable fuels are calculated. In conducting this analysis, ORNL considered the full economic cost of importing petroleum into the U.S. The full economic cost of importing petroleum into the U.S. is defined for this analysis to include two components in addition to the purchase price of petroleum itself. These are:
(1)The higher costs for oil imports resulting from the effect of U.S. import demand on the world oil price and OPEC market power (i.e., the so called “demand” or “monoposony” costs); and
(2)the risk of reductions in U.S. economic output and disruption of the U.S. economy caused by sudden disruptions in the supply of imported oil to the U.S. (i.e., macroeconomic disruption/adjustment costs). 1. Effect of Oil Use on Long-Run Oil Price, U.S. Import Costs, and Economic Output The first component of the full economic costs of importing petroleum into the U.S. follows from the effect of U.S. import demand on the world oil price over the long-run. Because the U.S. is a sufficiently large purchaser of foreign oil supplies, its purchases can affect the world oil price. This monopsony power means that increases in U.S. petroleum demand can cause the world price of crude oil to rise, and conversely, that reduced U.S. petroleum demand can reduce the world price of crude oil. Thus, one consequence of decreasing U.S. oil purchases due to increased use of renewable fuel is the potential decrease in the crude oil price paid for all crude oil purchased. 2. Short-Run Disruption Premium From Expected Costs of Sudden Supply Disruptions The second component of the external economic costs resulting from U.S. oil imports arises from the vulnerability of the U.S. economy to oil shocks. The cost of shocks depends on their likelihood, size, and length, the capabilities of the market and U.S. Strategic Petroleum Reserve (SPR), the largest stockpile of government-owned emergency crude oil in the world, to respond, and the sensitivity of the U.S. economy to sudden price increases. While the total vulnerability of the U.S. economy to oil price shocks depends on the levels of both U.S. petroleum consumption and imports, variation in import levels or demand flexibility can affect the magnitude of potential increases in oil price due to supply disruptions. Disruptions are uncertain events, so the costs of alternative possible disruptions are weighted by disruption probabilities. The probabilities used by the ORNL study are based on a 2005 Energy Modeling Forum 117 synthesis of expert judgment and are used to determine an expected value of disruption costs, and the change in those expected costs given reduced U.S. oil imports. 3. Costs of Existing U.S. Energy Security Policies The last often-identified component of the full economic costs of U.S. oil imports is the costs to the U.S. taxpayers of existing U.S. energy security policies. The two primary examples are maintaining a military presence to help secure stable oil supply from potentially vulnerable regions of the world and maintaining the SPR to provide buffer supplies and help protect the U.S. economy from the consequences of global oil supply disruptions. U.S. military costs are excluded from the analysis performed by ORNL because their attribution to particular missions or activities is difficult. Most military forces serve a broad range of security and foreign policy objectives. Attempts to attribute some share of U.S. military costs to oil imports are further challenged by the need to estimate how those costs might vary with incremental variations in U.S. oil imports. Similarly, while the costs for building and maintaining the SPR are more clearly related to U.S. oil use and imports, historically these costs have not varied in response to changes in U.S. oil import levels. Thus, while SPR is factored into the ORNL analysis, the cost of maintaining the SPR is excluded. As stated earlier, we have placed the draft report in the docket of this rulemaking for the purposes of inviting further consideration. However, the draft results of that report have not been used in quantifying the impacts of this rule. X. Agricultural Sector Economic Impacts As described in the Notice of Proposed Rulemaking (NPRM), we used the Forest and Agricultural Sector Optimization Model (FASOM) developed by Professor Bruce McCarl of Texas A&M University and others, to estimate the agricultural sector impacts of increasing renewable fuel volumes required by the RFS and for those volumes anticipated by EIA for 2012. Although current renewable fuel volume predictions are higher than the scenarios described in this rulemaking, we based our analysis on assumptions developed during the NPRM process. Our agricultural sector analysis considered the impacts of the domestic production of renewable fuels. Therefore, when we refer to either the RFS Case or the EIA Case, we include only renewable fuels produced from feedstocks grown in the U.S. 118 At the time the NPRM was published, we had not yet finished our analysis of the agricultural impacts associated with the RFS. In the NPRM, we stated our intent to have the analysis completed in time for the Final Rulemaking (FRM). In the proposal we described our plan to evaluate the effect of increasing renewable fuels volumes on U.S. commodity prices, renewable fuel byproduct prices, livestock feed sources, land use, exports, and farm income. The results of this analysis are summarized in this section. Additional details are included in the Regulatory Impact Analysis (RIA). 117 Stanford Energy Modeling Forum, Phillip C. Beccue and Hillard G. Huntington, “An Assessment of Oil Market Disruption Risks,” Final Report, EMF SR 8, October, 2005. 118 The RIA contains additional information on the renewable fuels volumes analyzed for this rulemaking. FASOM is a long-term economic model of the U.S. agriculture sector that attempts to maximize total revenues for producers while meeting the demands of consumers. Using a number of inputs, FASOM estimates which crops, livestock, and processed agricultural products will be produced in the U.S. The cost of these and other inputs are used to determine the price and level of production of commodities (e.g., field crops, livestock, and biofuel products). FASOM does not capture short-term fluctuations (i.e., month-to-month, annual) in prices and production, however, as it is designed to identify long-term trends (i.e., five to ten years). FASOM predicts that as renewable fuel volumes increase, corn prices will rise by about 18 cents (RFS Case) and 39 cents (EIA Case) above the Reference Case price of $2.32 per bushel. For consistency, all of the dollar estimates are presented in 2004 dollars. Soybean prices will rise by about 18 cents (RFS Case) and 21 cents (EIA Case) above the Reference Case price of $5.26 per bushel by 2012. Since biodiesel volumes will not increase significantly in either the RFS or EIA scenarios, FASOM does not predict significant changes in the soybean related markets with respect to usage changes, or most other variables of interest for this rulemaking. The one exception is U.S. soybean exports, which are affected modestly. Changes in corn use can be seen by the changing percentage of corn used for ethanol. In 2005, approximately 12 percent of the corn supply was used for ethanol production, however we estimate the amount of corn used for ethanol in 2012 will increase to 20 percent (RFS Case) and 26 percent (EIA Case). The rising price of corn and soybeans has a direct impact on how corn is used. Higher domestic corn prices lead to lower U.S. exports as the world markets shift to other sources of these products or expand the use of substitute grains. FASOM estimates that U.S. corn exports will drop from about 2 billion bushels in our Reference Case, to 1.6 billion bushels (RFS Case) and 1.3 billion bushels (EIA Case) by 2012. U.S. exports of corn are estimated to drop by about 19 percent by 2012 for the RFS Case and by roughly 38 percent in the EIA Case. In value terms, U.S. exports of corn fall by $573 million in the RFS Case and by $1.29 billion in the EIA Case in 2012. The impact on domestic livestock feed due to higher corn prices and higher U.S. demand for corn in ethanol is also partially offset by decreasing the use of corn for U.S. livestock feed. Substitutes are available for corn as a feedstock, and this market is price sensitive. One alternate feedstock is distillers dried grains with solubles (DDGS), a byproduct associated with the dry milling of ethanol production. Since FASOM predicts relatively flat prices for DDGS across all ethanol volume scenarios, the result is a significant increase in the use of DDGS as a feed source. We estimate DDGS in feed for the RFS case will almost double by 2012, increasing from 8.5 million tons to 15.2 million tons. Under the EIA Case, we expect DDGS to increase to 22.2 million tons by 2012. The increase in soybean prices is estimated to cause a decline in U.S. soybean exports. In terms of export earnings, U.S. exports of soybeans fall by $220 million in the RFS Case and by $194 million in the EIA Case in 2012. The increase in renewable fuel production provides a significant increase in net farm income to the U.S. agricultural sector. FASOM predicts that in 2012, net U.S. farm income will increase by $2.6 billion dollars in the RFS renewable fuel volumes case (RFS Case) and $5.4 billion in the EIA renewable fuel volumes case (EIA Case). The RFS and EIA farm revenue increases represent roughly a 5 and 10 percent increase, respectively, in U.S. net farm income from the sale of farm commodities over the Reference Case of roughly $53 billion. Higher corn prices will have a direct impact on the value of U.S. agricultural land. As demand for corn and farm products increases, the price of U.S. farm land will also increase. Our analysis shows that in 2012, higher renewable fuel volumes increase land prices by about 8 percent (RFS Case) and 17 percent (EIA Case). Much of the high quality, suitable land in the U.S. is already being used to produce corn. FASOM estimates an increase of 1.6 million acres (RFS Case) and 2.6 million acres (EIA Case) above the 78.5 million corn acres harvested in the Reference Case in 2012. Due to this higher value of land, we are predicting that farms will withdraw a portion of the land currently in the Conservation Reserve Program (CRP), about 2.3 million acres (RFS Case) and 2.5 million acres (EIA Case) out of the approximately 40 million acres in CRP. 119 119 Since much of the CRP land is ill suited for corn or soybean production, it is unlikely this land will go directly into corn or soybean production but instead will more likely be used to replace other agricultural land uses displaced by expanded corn and soybean production. FASOM estimates U.S. annual wholesale food costs will increase by approximately $2.2 billion with the RFS renewable volumes and $3.7 billion with the EIA renewable volumes by 2012. These costs translate to approximately $7 per person per year (RFS case) and $12 per person per year (EIA case). In the proposal, we noted that expansion in the use of renewable fuels also raises the issue of whether water quality and rural ecosystems in general could be affected due to increased production of agricultural feedstocks used to produce greater volumes of renewable fuels. We received one comment from Marathon asserting that our environmental assessment was incomplete and did not address water quality issues. In the time frame to complete this rulemaking, we were not able to conduct a comprehensive assessment of the environmental impacts in the agricultural sector of the wider use of renewable fuels. However, we have considered two indicators—fertilizer use on agricultural crops and Conservation Resource Program
(CRP)lands—that may relate to environmental quality and water quality from the production of renewable fuels. The CRP is a voluntary program administered by the U.S. Department of Agriculture that helps defray the costs to farmers of taking agricultural lands out of production and placing them in CRP to provide environmental protection. As discussed in Section X, FASOM predicts the total amount of nitrogen applied on all farms will increase by 1.2 percent in the RFS Case and by 2 percent in the EIA Case, relative to the Reference Case in 2012. The total amount of phosphorous applied on all farms increases by 0.7 percent in the RFS Case and 1.2 percent in the EIA Case, relative to the Reference Case in 2012. Currently, there are approximately 40 million acres in the CRP. FASOM predicts 2.3 million acres (RFS Case) and 2.5 million acres (EIA Case) of land would be withdrawn from the CRP due to higher land values. XI. Public Participation Many interested parties participated in the rulemaking process that culminates with this final rule. This process provided opportunity for submitting written public comments following the proposal that we published on September 22, 2006 (71 FR 55552). We considered these comments in developing the final rule. In addition, we held a public hearing on the proposed rulemaking on October 13, 2006, and we have considered comments presented at the hearing. Throughout the rulemaking process, EPA met with stakeholders including representatives from the refining industry, renewable fuels production, and marketers and distributors, and others. The program we are finalizing today was developed as a collaborative effort with these stakeholders. We have prepared a detailed Summary and Analysis of Comments document, which describes comments we received on the proposal and our response to each of these comments. The Summary and Analysis of Comments is available in the docket for this rule at the Internet address listed under ADDRESSES , as well as on the Office of Transportation and Air Quality Web site ( *http://www.epa.gov/otaq/renewablefuels/index.htm* ). In addition, comments and responses for key issues are included throughout this preamble. XII. Administrative Requirements A. Executive Order 12866: Regulatory Planning and Review Under Executive Order
(EO)12866, (58 FR 51735, October 4, 1993) this action is a “significant regulatory action” because of the policy implications of the final rule. Even though EPA has estimated that renewable fuel use through 2012 will be sufficient through the operation of market forces to meet the levels required in the standard, the final rule reflects the first renewable fuel mandate at the federal level. Accordingly, EPA submitted this action to the Office of Management and Budget
(OMB)for review under EO 12866 and any changes made in response to OMB recommendations have been documented in the docket for this action. B. Paperwork Reduction Act The information collection requirements in this final rule have been submitted for approval to the Office of Management and Budget
(OMB)under the Paperwork Reduction Act, 44 U.S.C. 3501 *et seq.* The Information Collection Request
(ICR)prepared by EPA has been assigned EPA ICR number 2242.02. The information collection requirements are not enforceable until OMB approves them. The information is planned to be collected to ensure that the required amount of renewable fuel is used each year. The credit trading program required by the Energy Policy Act will be satisfied through a program utilizing Renewable Identification Numbers (RINs), which are assigned when renewable fuel is produced in or imported to geographic areas covered by the rule. Production and importation of renewable fuel will serve as a surrogate measure of renewable fuel consumption. Our final RIN-based program will fulfill all the functions of a credit trading program, and thus will meet the Energy Policy Act's requirements. For each calendar year, each obligated party will be required to submit a report to the Agency documenting the RINs it acquired, and showing that the sum of all RINs acquired is equal to or greater than its renewable volume obligation. The Agency could then verify that the RINs used for compliance purposes were valid by simply comparing RINs reported by producers to RINs claimed by obligated parties. For fuel standards, Section 208(a) of the Clean Air Act requires that manufacturers provide information the Administrator may reasonably require to determine compliance with the regulations; submission of the information is therefore mandatory. We will consider confidential all information meeting the requirements of Section 208(c) of the Clean Air Act. The annual public reporting and recordkeeping burden for this collection of information is estimated to be 3.3 hours per response. A document entitled “Information Collection Request (ICR); OMB-83 Supporting Statement, Environmental Protection Agency, Office of Air and Radiation,” has been placed in the public docket. The supporting statement provides a detailed explanation of the Agency's estimates by collection activity and explains how comments may be submitted by interested parties. The estimates contained in the docket are briefly summarized here: Estimated total number of potential respondents: 6,425. Estimated total number of responses: 13,380. Estimated total annual burden hours: 43,030. Estimated total respondent cost (estimated at $71 per hour): $3,055,130. Estimated total non-postage purchased services (estimated at $142 per hour): $5,219,920. EPA received various comments on the rulemaking provisions covered by the proposed ICR. All comments that were submitted to EPA are considered in the Summary and Analysis of Comments, which can be found in the docket. In response to comments, we have increased the frequency of reporting for transaction and summary reports from annually to quarterly. We have also removed a burden for small refiners that was associated with applying for small-refiner flexibilities. The burdens and costs shown above account for these changes. Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose the information. An agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is approved by OMB, the Agency will publish a technical amendment to 40 CFR part 9 in the **Federal Register** to display the OMB control number for the approved information collection requirements contained in this final rule. C. Regulatory Flexibility Act 1. Overview The Regulatory Flexibility Act
(RFA)generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of today's rule on small entities, small entity is defined as:
(1)A small business as defined by the Small Business Administration's
(SBA)regulations at 13 CFR 121.201 (see table below);
(2)a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and
(3)a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field. The following table provides an overview of the primary SBA small business categories potentially affected by this regulation: 120 In the NPRM, we also referred to a 125,000 barrels of crude per day
(bpcd)crude capacity limit. This criterion was inadvertently used and is not applicable for this program (as it only applies in cases of government procurement). We note that the number of small entities remains the same whether this criterion is used or not. Industry Defined as small entity by SBA if NAICS codes a Gasoline refiners ≤1,500 employees. 120 324110 a North American Industrial Classification System. EPA has determined that it is not necessary to prepare a regulatory flexibility analysis in connection with this final rule. 2. Background Since the vast majority of crude oil produced in or imported into the U.S. is consumed as gasoline or diesel fuel, concerns about our dependence on foreign sources of crude oil has renewed interest in renewable transportation fuels. The passage of the Energy Policy Act of 2005 demonstrated a strong commitment on the part of U.S. policymakers to consider additional means of supporting renewable fuels as a supplement to petroleum-based fuels in the transportation sector. Section 1501 of the Energy Policy Act, which was added to the CAA as Section 211(o), requires EPA to establish the RFS program to ensure that the pool of gasoline sold in the contiguous 48 states contains specific volumes of renewable fuel for each calendar year starting with 2006. The Agency is required to set a standard for each year representing the amount of renewable fuel that obligated parties (e.g., refiners, blenders, and importers) must use as a percentage of gasoline sold or introduced into commerce, and the Agency is required to promulgate a credit trading program for the RFS program. 3. Small Refineries Versus Small Refiners Title XV (Ethanol and Motor Fuels) of the Energy Policy Act provides, at Section 1501(a)(2) [42 U.S.C. 7545(o)(9)(A)-(D)], special provisions for “small refineries”, such as a temporary exemption from the standards until calendar year 2011. The Act defines the term “small refinery” as “* * * a refinery for which the average aggregate daily crude oil throughput for a calendar year * * * does not exceed 75,000 barrels.” As shown in the table above, this term is different than SBA's small business category for gasoline *refiners* , which is what the Regulatory Flexibility Act is concerned with. EPA is required under the RFA to consider impacts on small entities meeting SBA's small business definition; these entities are referred to as “small refiners” for our regulatory flexibility analysis under SBREFA. A small refinery, per the Energy Policy Act, is a refinery where the annual crude throughput is less than or equal to 75,000 barrels (i.e., a small-capacity refinery), and could be owned by a larger refiner that exceeds SBA's small entity size standards. The small business employee criteria were established for SBA's small business definition to set apart those companies which are most likely to be at an inherent economic disadvantage relative to larger businesses. 4. Summary of Potentially Affected Small Entities The refiners that are potentially affected by this rule are those that produce gasoline. For our recent final rule “Control of Hazardous Air Pollutants From Mobile Sources” (72 FR 8428, February 26, 2007), we performed an industry characterization of potentially affected gasoline refiners. We used that industry characterization to determine which refiners would also meet the SBA definition of a small entity. From that industry characterization, and further analysis following the Notice of Proposed Rulemaking (71 FR 55552, September 22, 2006), we have determined that there are 15 gasoline refiners who own 16 refineries (14 refiners own one refinery each, the remaining refiner owns two refineries) that meet the definition of a small refiner. Of the 16 refineries, 13 also meet the Energy Policy Act's definition of a small refinery. 5. Impact of the Regulations on Small Entities As previously stated, many aspects of the RFS program, such as the required amount of annual renewable fuel volumes, are specified in the Energy Policy Act. As discussed above in Section II.A.1, the annual projections of ethanol production to satisfy market demand exceed the required annual renewable fuel volumes. When the small refinery exemption ends, it is anticipated that there will be over one billion gallons in excess RINs available. We believe that this large volume of excess RINs will also lower the costs of this program. Thus, with the short-term relief provided under the Energy Policy Act for small refineries, and the anticipated low cost of RINs when the exemption expires, we believe that this program will not impose a significant economic burden on small refineries, small refiners, or any other obligated party. Therefore, we have determined that this rule will not have a significant economic impact on a substantial number of small entities. When the Agency certifies that a rule will not have a significant economic impact on a substantial number of small entities, EPA's policy is to make an assessment of the rule's impact on any small entities and to engage the potentially regulated entities in a dialog regarding the rule, and minimize the impact to the extent feasible. The following sections discuss our outreach with the potentially affected small entities and regulatory flexibilities to decrease the burden on these entities in compliance with the requirements of the RFS program. 6. Small Refiner Outreach We do not believe that the RFS program would have a significant economic impact on a substantial number of small entities, however we have still tried to reduce the impact of this rule on small entities. Prior to issuing the proposed rule, we held meetings with small refiners to discuss the requirements of the RFS program and the special provisions offered by the Energy Policy Act for small refineries. The Energy Policy Act set out the following provisions for small refineries: • A temporary exemption from the Renewable Fuels Standard requirement until 2011; • An extension of the temporary exemption period for at least two years for any small refinery where it is determined that the refinery would be subject to a disproportionate economic hardship if required to comply; • Any small refinery may petition, at any time, for an exemption based on disproportionate economic hardship; and, • A small refinery may waive its temporary exemption to participate in the credit generation program, or it may also “opt-in”, by waiving its temporary exemption, to be subject to the RFS requirement. During these meetings with the small refiners we also discussed the impacts of these provisions being offered to small refineries only. Three refiners met the definition of a small refiner, but their refineries did not meet the Act's definition of a small refinery; which naturally concerned the small refiners. Another concern that the small refiners had was that if this rule were to have a significant economic impact on a substantial number of small entities a lengthy SBREFA process would ensue (which would delay the promulgation of the RFS rulemaking) and thus provide less lead time for these small entities prior to the RFS program start date. Following our discussions with the small refiners, they provided three suggested regulatory flexibility options that they believed could further assist affected small entities in complying with the RFS program standard:
(1)That all small *refiners* be afforded the Act's small *refinery* temporary exemption,
(2)that small refiners be allowed to generate credits if they elect to comply with the RFS program standard prior to the 2011 small refinery compliance date, and
(3)relieve small refiners who generate blending credits of the RFS program compliance requirements. We agreed with the small refiners' suggestion that small refiners be afforded the same temporary exemption that the Act specifies for small refineries. This relief would apply to refiners who meet the 1,500 employee count criteria, as well as the crude capacity criteria that we have used in previous fuels programs when providing relief for small refiners. Regarding the small refiners' second and third suggestions regarding credits, we note that the RIN-based program will automatically provide them with credit for any renewables that they blend into their motor fuels. Until 2011, small refiners will essentially be treated as oxygenate blenders and may separate RINs from batches and trade or sell these RINs, unless they choose to opt-in to the program. 7. Reporting, Recordkeeping, and Compliance Requirements Registration, recordkeeping and reporting are necessary to track compliance with the renewable fuels standard and transactions involving RINs, and these compliance requirements will be similar to those required under our previous and current 40 CFR part 80 fuel compliance programs. We will use the same basic forms for RFS program registration that we use under the reformulated gasoline
(RFG)and anti-dumping program, as these forms are well known in the regulated community and are simple to fill out. We will use a simplified method of reporting via the Agency's Central Data Exchange (CDX), which will reduce the reporting burden on regulated parties. Records related to RIN transactions may be kept in any format and the period of record retention by reporting parties is five years, similar to other fuel programs. Records to be retained include copies of all compliance reports submitted to EPA and copies of product transfer documents (PTDs). Sections IV and V, above, contain more detailed discussions on the registration, recordkeeping, reporting, and compliance requirements of this final rule. 8. Related Federal Rules We are aware of a few other current or proposed Federal rules that are related to this rule. The primary related federal rules are the Mobile Source Air Toxics (MSAT2) rule (72 FR 8428, February 26, 2007), the Tier 2 Vehicle/Gasoline Sulfur rulemaking (65 FR 6698, February 10, 2000), and the fuel sulfur rules for highway diesel (66 FR 5002, January 18, 2001) and nonroad diesel (69 FR 38958, June 29, 2004). 9. Conclusions As stated above, based on the statutory relief provided by the Energy Policy Act for small refineries, we are certifying that this rule will not have a significant economic impact on a substantial number of small entities. Additionally, we believe that extending the small refinery exemption to small refiners would further reduce the economic impacts on small entities. We believe that small refiners generally lack the resources available to larger companies, and therefore find it appropriate to extend this exemption to all small refiners. Thus, we are extending the small refinery temporary exemption to all qualified small refiners. Small refiners will also be permitted to separate RINs from batches and trade or sell these RINs prior to 2011 if the small refiner operates as an ethanol blender. Past fuels rulemakings have included a provision that, for the purposes of the regulatory flexibility provisions for small entities, a refiner must also have an average crude capacity of no more than 155,000 barrels of crude per day (bpcd). To be consistent with these previous rules, we are finalizing in this rule that refiners that meet this criterion (in addition to having no more than 1,500 total corporate employees) will be considered small refiners for the purposes of the regulatory flexibility provisions for this rulemaking. Since the RFS program would have no significant economic impact on a substantial number of small entities with only the relief required in the Energy Policy Act for small refineries, it also follows that the rule will have no significant economic impact on a substantial number of small entities with the additional relief this final rule provides for small refiners. D. Unfunded Mandates Reform Act Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104-4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local, and tribal governments and the private sector. Under section 202 of the UMRA, EPA generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with “Federal mandates” that may result in expenditures to State, local, and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any one year. Before promulgating an EPA rule for which a written statement is needed, section 205 of the UMRA generally requires EPA to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost-effective or least burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are inconsistent with applicable law. Moreover, section 205 allows EPA to adopt an alternative other than the least costly, most cost-effective or least burdensome alternative if the Administrator publishes with the final rule an explanation why that alternative was not adopted. Before EPA establishes any regulatory requirements that may significantly or uniquely affect small governments, including tribal governments, it must have developed under Section 203 of the UMRA a small government agency plan. The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of EPA regulatory programs with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements. EPA has determined that this rule does not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any one year. EPA has estimated that renewable fuel use through 2012 will be sufficient to meet the required levels. Therefore, individual refiners, blenders, and importers are already on track to meet rule obligations through normal market-driven incentives. Thus, today's rule is not subject to the requirements of Sections 202 and 205 of the UMRA. EPA has determined that this rule contains no regulatory requirements that might significantly or uniquely affect small governments. Compliance with the mandates of the RFS rule, including the reporting and recordkeeping requirements, are the responsibility of exporters, producers, and importers of renewable fuel and gasoline, and not small governments. E. Executive Order 13132: Federalism Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure “meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications.” “Policies that have federalism implications” is defined in the Executive Order to include regulations that have “substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.” This final rule does not have federalism implications. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. Thus, Executive Order 13132 does not apply to this rule. In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, EPA specifically solicited comment on the proposed rule from State and local officials. A number of states commented on the proposed rule. These comments are available in the rulemaking docket, and are summarized and addressed in the Summary and Analysis document. F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (65 FR 67249, November 9, 2000), requires EPA to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.” This final rule does not have tribal implications, as specified in Executive Order 13175. This rule will be implemented at the Federal level and will apply to refiners, blenders, and importers. Tribal governments will be affected only to the extent they purchase and use regulated fuels. Thus, Executive Order 13175 does not apply to this rule. G. Executive Order 13045: Protection of Children From Environmental Health and Safety Risks Executive Order 13045: “Protection of Children from Environmental Health Risks and Safety Risks” (62 FR 19885, April 23, 1997) applies to any rule that:
(1)Is determined to be “economically significant” as defined under Executive Order 12866, and
(2)concerns an environmental health or safety risk that EPA has reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria, the Agency must evaluate the environmental health or safety effects of the planned rule on children, and explain why the planned regulation is preferable to other potentially effective and reasonably feasible alternatives considered by the Agency. EPA interprets EO 13045 as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5-501 of the EO has the potential to influence the regulation. This final rule is not subject to EO 13045 because it does not establish an environmental standard intended to mitigate health or safety risks and because it implements specific standards established by Congress in statutes. H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use This rule is not a “significant energy action” as defined in Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355 (May 22, 2001)) because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. EPA expects the provisions to have very little effect on the national fuel supply since normal market forces alone are promoting greater renewable fuel use than required by the RFS mandate. We discuss our analysis of the energy and supply effects of the increased use of renewable fuels in Sections VI and X of this preamble. I. National Technology Transfer Advancement Act As noted in the proposed rule, Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (“NTTAA”), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. The NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards. This rulemaking involves technical standards. EPA has decided to use ASTM D6751-06a “Standard Specification for Biodiesel Fuel Blend Stock
(B100)for Middle Distillate Fuels”. This standard was developed by ASTM International (originally known as the American Society for Testing and Materials), Subcommittee D02.E0, and was approved in August 2006. The standard may be obtained through the ASTM Web site ( *www.astm.org* ) or by calling ASTM at
(610)832-9585. ASTM D6751-06a meets the objectives of this final rule because it establishes one of the criteria by which biodiesel is defined. J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations Executive Order
(EO)12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States. EPA lacks the discretionary authority to address environmental justice in this final rulemaking since the Agency is implementing specific standards established by Congress in statutes. Although EPA lacks authority to modify today's regulatory decision on the basis of environmental justice considerations, EPA nevertheless determined that this final rule does not have a disproportionately high and adverse human health or environmental impact on minority or low-income populations. K. Congressional Review Act The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. EPA will submit a report containing this rule and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication of the rule in the **Federal Register** . A Major rule cannot take effect until 60 days after it is published in the **Federal Register** . This action is not a “major rule” as defined by 5 U.S.C. 804(2). The effective date of the rule is September 1, 2007. L. Clean Air Act Section 307(d) This rule is subject to Section 307(d) of the CAA. Section 307(d)(7)(B) provides that “[o]nly an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review.” This section also provides a mechanism for the EPA to convene a proceeding for reconsideration, “[i]f the person raising an objection can demonstrate to the EPA that it was impracticable to raise such objection within [the period for public comment] or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule.” Any person seeking to make such a demonstration to the EPA should submit a Petition for Reconsideration to the Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., NW., Washington, DC 20460, with a copy to both the person(s) listed in the preceding FOR FURTHER INFORMATION CONTACT section, and the Director of the Air and Radiation Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200 Pennsylvania Ave., NW., Washington, DC 20460. XIII. Statutory Authority Statutory authority for the rules finalized today can be found in section 211 of the Clean Air Act, 42 U.S.C. 7545. Additional support for the procedural and compliance related aspects of today's rule, including the recordkeeping requirements, come from Sections 114, 208, and 301(a) of the CAA, 42 U.S.C. 7414, 7542, and 7601(a). List of Subjects in 40 CFR Part 80 Environmental protection, Air pollution control, Fuel additives, Gasoline, Imports, Incorporation by reference, Labeling, Motor vehicle pollution, Penalties, Reporting and recordkeeping requirements. Dated: April 10, 2007. Stephen L. Johnson, Administrator. 40 CFR part 80 is amended as follows: PART 80—REGULATION OF FUEL AND FUEL ADDITIVES 1. The authority citation for part 80 continues to read as follows: Authority: 42 U.S.C. 7414, 7542, 7545, and 7601(a). 2. Section 80.1100 is revised to read as follows: § 80.1100 How is the statutory default requirement for 2006 implemented?
(a)*Definitions.* For calendar year 2006, the definitions of section 80.2 and the following additional definitions apply to this section.
(1)*Renewable fuel.*
(i)*Renewable fuel* means motor vehicle fuel that is used to replace or reduce the quantity of fossil fuel present in a fuel mixture used to operate a motor vehicle, and which:
(A)Is produced from grain, starch, oil seeds, vegetable, animal, or fish materials including fats, greases, and oils, sugarcane, sugar beets, sugar components, tobacco, potatoes, or other biomass; or
(B)Is natural gas produced from a biogas source, including a landfill, sewage waste treatment plant, feedlot, or other place where decaying organic material is found.
(ii)The term “renewable fuel” includes cellulosic biomass ethanol, waste derived ethanol, biodiesel, and any blending components derived from renewable fuel.
(2)*Cellulosic biomass ethanol* means ethanol derived from any lignocellulosic or hemicellulosic matter that is available on a renewable or recurring basis, including dedicated energy crops and trees, wood and wood residues, plants, grasses, agricultural residues, fibers, animal wastes and other waste materials, and municipal solid waste. The term also includes any ethanol produced in facilities where animal wastes or other waste materials are digested or otherwise used to displace 90 percent or more of the fossil fuel normally used in the production of ethanol.
(3)*Waste derived ethanol* means ethanol derived from animal wastes, including poultry fats and poultry wastes, and other waste materials, or municipal solid waste.
(4)*Small refinery* means a refinery for which the average aggregate daily crude oil throughput for a calendar year (as determined by dividing the aggregate throughput for the calendar year by the number of days in the calendar year) does not exceed 75,000 barrels.
(5)*Biodiesel* means a diesel fuel substitute produced from nonpetroleum renewable resources that meets the registration requirements for fuels and fuel additives established by the Environmental Protection Agency under section 211 of the Clean Air Act. It includes biodiesel derived from animal wastes (including poultry fats and poultry wastes) and other waste materials, or biodiesel derived from municipal solid waste and sludges and oils derived from wastewater and the treatment of wastewater.
(b)*Renewable Fuel Standard for 2006.* The percentage of renewable fuel in the total volume of gasoline sold or dispensed to consumers in 2006 in the United States shall be a minimum of 2.78 percent on an annual average volume basis.
(c)*Responsible parties.* Parties collectively responsible for attainment of the standard in paragraph
(b)of this section are refiners (including blenders) and importers of gasoline. However, a party that is a refiner only because he owns or operates a small refinery is exempt from this responsibility.
(d)*EPA determination of attainment.* EPA will determine after the close of 2006 whether or not the requirement in paragraph
(b)of this section has been met. EPA will base this determination on information routinely published by the Energy Information Administration on the annual domestic volume of gasoline sold or dispensed to U.S. consumers and of ethanol produced for use in such gasoline, supplemented by readily available information concerning the use in motor fuel of other renewable fuels such as cellulosic biomass ethanol, waste derived ethanol, biodiesel, and other non-ethanol renewable fuels.
(1)The renewable fuel volume will equal the sum of all renewable fuel volumes used in motor fuel, provided that:
(i)One gallon of cellulosic biomass ethanol or waste derived ethanol shall be considered to be the equivalent of 2.5 gallons of renewable fuel; and
(ii)Only the renewable fuel portion of blending components derived from renewable fuel shall be counted towards the renewable fuel volume.
(2)If the nationwide average volume percent of renewable fuel in gasoline in 2006 is equal to or greater than the standard in paragraph
(b)of this section, the standard has been met.
(e)*Consequence of nonattainment in 2006.* In the event that EPA determines that the requirement in paragraph
(b)of this section has not been attained in 2006, a deficit carryover volume shall be added to the renewable fuel volume obligation for 2007 for use in calculating the standard applicable to gasoline in 2007.
(1)The deficit carryover volume shall be calculated as follows: DC = Vgas * (Rs−Ra) Where: DC = Deficit carryover, in gallons, of renewable fuel. Vgas = Volume of gasoline sold or dispensed to U.S. consumers in 2006, in gallons. Rs = 0.0278. Ra = Ratio of renewable fuel volume divided by total gasoline volume determined in accordance with paragraph (d)(2) of this section.
(2)There shall be no other consequence of failure to attain the standard in paragraph
(b)of this section in 2006 for any of the parties in paragraph
(c)of this section. 3. Section 80.1101 is added to read as follows: § 80.1101 Definitions. The definitions of § 80.2 and the following additional definitions apply for the purposes of this subpart. For calendar year 2007 and beyond, the definitions in this section § 80.1101 supplant those in § 80.1100.
(a)*Cellulosic biomass ethanol* means either of the following:
(1)Ethanol derived from any lignocellulosic or hemicellulosic matter that is available on a renewable or recurring basis and includes any of the following:
(i)Dedicated energy crops and trees.
(ii)Wood and wood residues.
(iii)Plants.
(iv)Grasses.
(v)Agricultural residues.
(vi)Animal wastes and other waste materials, the latter of which may include waste materials that are residues (e.g., residual tops, branches, and limbs from a tree farm).
(vii)Municipal solid waste.
(2)Ethanol made at facilities at which animal wastes or other waste materials are digested or otherwise used onsite to displace 90 percent or more of the fossil fuel that is combusted to produce thermal energy integral to the process of making ethanol, by:
(i)The direct combustion of the waste materials or a byproduct resulting from digestion of such waste materials (e.g., methane from animal wastes) to make thermal energy; and/or
(ii)The use of waste heat captured from an off-site combustion process as a source of thermal energy.
(b)*Waste derived ethanol* means ethanol derived from either of the following:
(1)Animal wastes, including poultry fats and poultry wastes, and other waste materials.
(2)Municipal solid waste.
(c)*Biogas* means methane or other hydrocarbon gas produced from decaying organic material, including landfills, sewage waste treatment plants, and animal feedlots.
(d)*Renewable fuel.*
(1)*Renewable fuel* is any motor vehicle fuel that is used to replace or reduce the quantity of fossil fuel present in a fuel mixture used to fuel a motor vehicle, and is produced from any of the following:
(i)Grain.
(ii)Starch.
(iii)Oilseeds.
(iv)Vegetable, animal, or fish materials including fats, greases, and oils.
(v)Sugarcane.
(vi)Sugar beets.
(vii)Sugar components.
(viii)Tobacco.
(ix)Potatoes.
(x)Other biomass.
(xi)Natural gas produced from a biogas source, including a landfill, sewage waste treatment plant, feedlot, or other place where there is decaying organic material.
(2)The term “Renewable fuel” includes cellulosic biomass ethanol, waste derived ethanol, biodiesel (mono-alky ester), non-ester renewable diesel, and blending components derived from renewable fuel.
(3)Ethanol covered by this definition shall be denatured as required and defined in 27 CFR parts 20 and 21.
(4)Small volume additives (excluding denaturants) less than 1.0 percent of the total volume of a renewable fuel shall be counted as part of the total renewable fuel volume.
(5)A fuel produced by a renewable fuel producer that is used in boilers or heaters is not a motor vehicle fuel and therefore is not a renewable fuel.
(e)*Blending component* has the same meaning as “Gasoline blending stock, blendstock, or component” as defined at § 80.2(s), for which the portion that can be counted as renewable fuel is calculated as set forth in § 80.1115(a).
(f)*Motor vehicle* has the meaning given in Section 216(2) of the Clean Air Act (42 U.S.C. 7550).
(g)*Small refinery* means a refinery for which the average aggregate daily crude oil throughput for the calendar year 2004 (as determined by dividing the aggregate throughput for the calendar year by the number of days in the calendar year) does not exceed 75,000 barrels.
(h)*Biodiesel (mono-alkyl ester)* means a motor vehicle fuel or fuel additive which is all the following:
(1)Registered as a motor vehicle fuel or fuel additive under 40 CFR part 79.
(2)A mono-alkyl ester.
(3)Meets ASTM D-6751-07, entitled “Standard Specification for Biodiesel Fuel Blendstock
(B100)for Middle Distillate Fuels.” ASTM D-6751-07 is incorporated by reference. This incorporation by reference was approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. A copy may be obtained from the American Society for Testing and Materials, 100 Barr Harbor Drive, West Conshohocken, Pennsylvania. A copy may be inspected at the EPA Docket Center, Docket No. EPA-HQ-OAR-2005-0161, EPA/DC, EPA West, Room 3334, 1301 Constitution Ave., NW., Washington, DC, or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to: *http://www.archives.gov/federal-register/cfr/ibr-locations.html.*
(4)Intended for use in engines that are designed to run on conventional diesel fuel.
(5)Derived from nonpetroleum renewable resources (as defined in paragraph
(m)of this section).
(i)*Non-ester renewable diesel* means a motor vehicle fuel or fuel additive which is all the following:
(1)Registered as a motor vehicle fuel or fuel additive under 40 CFR part 79.
(2)Not a mono-alkyl ester.
(3)Intended for use in engines that are designed to run on conventional diesel fuel.
(4)Derived from nonpetroleum renewable resources (as defined in paragraph
(m)of this section).
(j)*Renewable crude* means biologically derived liquid feedstocks including but not limited to poultry fats, poultry wastes, vegetable oil, and greases that are used as feedstocks to make gasoline or diesel fuels at production units as specified in paragraph
(k)of this section.
(k)*Renewable crude-based fuels* are renewable fuels that are gasoline or diesel products resulting from the processing of renewable crudes in production units within refineries or at dedicated facilities within refineries, that process petroleum based feedstocks and which make gasoline and diesel fuel.
(l)*Importers.* For the purposes of this subpart only, an importer of gasoline or renewable fuel is:
(1)Any person who brings gasoline or renewable fuel into the 48 contiguous states of the United States from a foreign country or from an area that has not opted in to the program requirements of this subpart pursuant to § 80.1143; and
(2)Any person who brings gasoline or renewable fuel into an area that has opted in to the program requirements of this subpart pursuant to § 80.1143.
(m)*Nonpetroleum renewable resources* include, but are not limited to the following:
(1)Plant oils.
(2)Animal fats and animal wastes, including poultry fats and poultry wastes, and other waste materials.
(3)Municipal solid waste and sludges and oils derived from wastewater and the treatment of wastewater.
(n)*Export of renewable fuel* means:
(1)Transfer of a batch of renewable fuel to a location outside the United States; and
(2)Transfer of a batch of renewable fuel from a location in the contiguous 48 states to Alaska, Hawaii, or a United States territory, unless that state or territory has received an approval from the Administrator to opt-in to the renewable fuel program pursuant to § 80.1143.
(o)*Renewable Identification Number (RIN)* , is a unique number generated to represent a volume of renewable fuel pursuant to §§ 80.1125 and 80.1126.
(1)*Gallon-RIN* is a RIN that represents an individual gallon of renewable fuel; and
(2)*Batch-RIN* is a RIN that represents multiple gallon-RINs.
(p)*Neat renewable fuel* is a renewable fuel to which only de minimus amounts of conventional gasoline or diesel have been added. §§ 80.1102 through 80.1103 [Reserved] 4. Sections 80.1102 and 80.1103 are reserved. 5. Sections 80.1104 through 80.1107 are added to read as follows: Subpart K—Renewable Fuel Standard Sec. 80.1104 What are the implementation dates for the Renewable Fuel Standard Program? 80.1105 What is the Renewable Fuel Standard? 80.1106 To whom does the Renewable Volume Obligation apply? 80.1107 How is the Renewable Volume Obligation calculated? § 80.1104 What are the implementation dates for the Renewable Fuel Standard Program? The RFS standards and other requirements of § 80.1101 and all sections following are effective beginning on September 1, 2007. § 80.1105 What is the Renewable Fuel Standard?
(a)The annual value of the renewable fuel standard for 2007 shall be 4.02 percent.
(b)Beginning with the 2008 compliance period, EPA will calculate the value of the annual standard and publish this value in the **Federal Register** by November 30 of the year preceding the compliance period.
(c)EPA will base the calculation of the standard on information provided by the Energy Information Administration regarding projected gasoline volumes and projected volumes of renewable fuel expected to be used in gasoline blending for the upcoming year.
(d)EPA will calculate the annual renewable fuel standard using the following equation: ER01MY07.059 Where: RFStd <sup>i</sup> = Renewable Fuel Standard, in year i, in percent. RFV <sup>i</sup> = Nationwide annual volume of renewable fuels required by section 211(o)(2)(B) of the Act (42 U.S.C. 7545), for year i, in gallons. G <sup>i</sup> = Amount of gasoline projected to be used in the 48 contiguous states, in year i, in gallons. R <sup>i</sup> = Amount of renewable fuel blended into gasoline that is projected to be used in the 48 contiguous states, in year i, in gallons. GS <sup>i</sup> = Amount of gasoline projected to be used in noncontiguous states or territories (if the state or territory opts-in), in year i, in gallons. RS <sup>i</sup> = Amount of renewable fuel blended into gasoline that is projected to be used in noncontiguous states or territories (if the state or territory opts-in), in year i, in gallons. GE <sup>i</sup> = Amount of gasoline projected to be produced by exempt small refineries and small refiners, in year i, in gallons (through 2010 only, except to the extent that a small refinery exemption is extended pursuant to § 80.1141(e)). Cell <sup>i</sup> = Beginning in 2013, the amount of renewable fuel that is required to come from cellulosic sources, in year i, in gallons.
(e)Beginning with the 2013 compliance period, EPA will calculate the value of the annual cellulosic standard and publish this value in the **Federal Register** by November 30 of the year preceding the compliance period.
(f)EPA will calculate the annual cellulosic standard using the following equation: ER01MY07.060 Where: RFCell <sup>i</sup> = Renewable Fuel Cellulosic Standard in year i, in percent. G <sup>i</sup> = Amount of gasoline projected to be used in the 48 contiguous states, in year i, in gallons. R <sup>i</sup> = Amount of renewable fuel blended into gasoline that is projected to be used in the 48 contiguous states, in year i, in gallons. GS <sup>i</sup> = Amount of gasoline projected to be used in noncontiguous states or territories (if the state or territory opts-in), in year i, in gallons. RS <sup>i</sup> = Amount of renewable fuel blended into gasoline that is projected to be used in noncontiguous states or territories (if the state or territory opts-in), in year i, in gallons. Cell <sup>i</sup> = Amount of renewable fuel that is required to come from cellulosic sources, in year i, in gallons. § 80.1106 To whom does the Renewable Volume Obligation apply?
(1)An obligated party is a refiner that produces gasoline within the 48 contiguous states, or an importer that imports gasoline into the 48 contiguous states. A party that simply adds renewable fuel to gasoline, as defined in § 80.1107(c), is not an obligated party.
(2)If the Administrator approves a petition of Alaska, Hawaii, or a United States territory to opt-in to the renewable fuel program under the provisions in § 80.1143, then “obligated party” shall also include any refiner that produces gasoline within that state or territory, or any importer that imports gasoline into that state or territory.
(3)For the purposes of this section, “gasoline” refers to any and all of the products specified at § 80.1107(c).
(b)For each compliance period starting with 2007, any obligated party is required to demonstrate, pursuant to § 80.1127, that it has satisfied the Renewable Volume Obligation for that compliance period, as specified in § 80.1107(a).
(c)An obligated party may comply with the requirements of paragraph
(b)of this section for all of its refineries in the aggregate, or for each refinery individually.
(d)An obligated party must comply with the requirements of paragraph
(b)of this section for all of its imported gasoline in the aggregate.
(e)An obligated party that is both a refiner and importer must comply with the requirements of paragraph
(b)of this section for its imported gasoline separately from gasoline produced by its refinery or refineries.
(f)Where a refinery or importer is jointly owned by two or more parties, the requirements of paragraph
(b)of this section may be met by one of the joint owners for all of the gasoline produced at the refinery, or all of the imported gasoline, in the aggregate, or each party may meet the requirements of paragraph
(b)of this section for the portion of the gasoline that it owns, as long as all of the gasoline produced at the refinery, or all of the imported gasoline, is accounted for in determining the renewable fuels obligation under § 80.1107.
(g)The requirements in paragraph
(b)of this section apply to the following compliance periods:
(1)For 2007, the compliance period is September 1 through December 31.
(2)Beginning in 2008, and every year thereafter, the compliance period is January 1 through December 31. § 80.1107 How is the Renewable Volume Obligation calculated?
(a)The Renewable Volume Obligation for an obligated party is determined according to the following formula: RVO <sup>i</sup> = (RFStd <sup>i</sup> * GV <sup>i</sup> ) + D <sup>i−1</sup> Where: RVO <sup>i</sup> = The Renewable Volume Obligation for an obligated party for calendar year i, in gallons of renewable fuel. RFStd <sup>i</sup> = The renewable fuel standard for calendar year i, determined by EPA pursuant to § 80.1105, in percent. GV <sup>i</sup> = The non-renewable gasoline volume, determined in accordance with paragraphs (b), (c), and
(d)of this section, which is produced or imported by the obligated party in calendar year i, in gallons. D <sup>i−1</sup> = Renewable fuel deficit carryover from the previous year, per § 80.1127(b), in gallons.
(b)The non-renewable gasoline volume for a refiner, blender, or importer for a given year, GV <sup>i</sup> , specified in paragraph
(a)of this section is calculated as follows: ER01MY07.061 Where: x = Individual batch of gasoline produced or imported in calendar year i. n = Total number of batches of gasoline produced or imported in calendar year i. G <sup>x</sup> = Volume of batch x of gasoline produced or imported, in gallons. y = Individual batch of renewable fuel blended into gasoline in calendar year i. m = Total number of batches of renewable fuel blended into gasoline in calendar year i. RB <sup>y</sup> = Volume of batch y of renewable fuel blended into gasoline, in gallons.
(c)All of the following products that are produced or imported during a compliance period, collectively called “gasoline” for the purposes of this section (unless otherwise specified), are to be included in the volume used to calculate a party's renewable volume obligation under paragraph
(a)of this section, except as provided in paragraph
(d)of this section:
(1)Reformulated gasoline, whether or not renewable fuel is later added to it.
(2)Conventional gasoline, whether or not renewable fuel is later added to it.
(3)Reformulated gasoline blendstock that becomes finished reformulated gasoline upon the addition of oxygenate (“RBOB”).
(4)Conventional gasoline blendstock that becomes finished conventional gasoline upon the addition of oxygenate (“CBOB”).
(5)Blendstock (including butane and gasoline treated as blendstock (“GTAB”)) that has been combined with other blendstock and/or finished gasoline to produce gasoline.
(6)Any gasoline, or any unfinished gasoline that becomes finished gasoline upon the addition of oxygenate, that is produced or imported to comply with a state or local fuels program.
(d)The following products are not included in the volume of gasoline produced or imported used to calculate a party's renewable volume obligation under paragraph
(a)of this section:
(1)Any renewable fuel as defined in § 80.1101(d).
(2)Blendstock that has not been combined with other blendstock or finished gasoline to produce gasoline.
(3)Gasoline produced or imported for use in Alaska, Hawaii, the Commonwealth of Puerto Rico, the U.S. Virgin Islands, Guam, American Samoa, and the Commonwealth of the Northern Marianas, unless the area has opted into the RFS program under § 80.1143.
(4)Gasoline produced by a small refinery that has an exemption under § 80.1141 or an approved small refiner that has an exemption under § 80.1142 until January 1, 2011 (or later, for small refineries, if their exemption is extended pursuant to § 80.1141(e)).
(5)Gasoline exported for use outside the 48 United States, and gasoline exported for use outside Alaska, Hawaii, the Commonwealth of Puerto Rico, the U.S. Virgin Islands, Guam, American Samoa, and the Commonwealth of the Northern Marianas, if the area has opted into the RFS program under § 80.1143.
(6)For blenders, the volume of finished gasoline, RBOB, or CBOB to which a blender adds blendstocks.
(7)The gasoline portion of transmix produced by a transmix processor, or the transmix blended into gasoline by a transmix blender, under 40 CFR 80.84. §§ 80.1108 through 80.1114 [Reserved] 6. Sections 80.1108 through 80.1114 are reserved. 7. Section 80.1115 is added to read as follows: § 80.1115 How are equivalence values assigned to renewable fuel? (a)(1) Each gallon of a renewable fuel shall be assigned an equivalence value by the producer or importer pursuant to paragraph
(b)or
(c)of this section.
(2)The equivalence value is a number that is used to determine how many gallon-RINs can be generated for a batch of renewable fuel according to § 80.1126.
(b)Equivalence values shall be assigned for certain renewable fuels as follows:
(1)Cellulosic biomass ethanol and waste derived ethanol produced on or before December 31, 2012 which is denatured shall have an equivalence value of 2.5.
(2)Ethanol other than cellulosic biomass ethanol or waste-derived ethanol which is denatured shall have an equivalence value of 1.0.
(3)Biodiesel (mono-alkyl ester) shall have an equivalence value of 1.5.
(4)Butanol shall have an equivalence value of 1.3.
(5)Non-ester renewable diesel, including that produced from coprocessing a renewable crude with fossil fuels in a hydrotreater, shall have an equivalence value of 1.7.
(6)All other renewable crude-based renewable fuels shall have an equivalence value of 1.0. (c)(1) For renewable fuels not listed in paragraph
(b)of this section, a producer or importer shall submit an application to the Agency for an equivalence value following the provisions of paragraph
(d)of this section.
(2)A producer or importer may also submit an application for an alternative equivalence value pursuant to paragraph
(d)of this section if the renewable fuel is listed in paragraph
(b)of this section, but the producer or importer has reason to believe that a different equivalence value than that listed in paragraph
(b)of this section is warranted.
(d)*Determination of equivalence values.*
(1)Except as provided in paragraph (d)(4) of this section, the equivalence value for renewable fuels described in paragraph
(c)of this section shall be calculated using the following formula: EV = (R / 0.931) * (EC / 77,550) Where: EV = Equivalence Value for the renewable fuel, rounded to the nearest tenth. R = Renewable content of the renewable fuel. This is a measure of the portion of a renewable fuel that came from a renewable source, expressed as a percent, on an energy basis. EC = Energy content of the renewable fuel, in Btu per gallon (lower heating value).
(2)The application for an equivalence value shall include a technical justification that includes a description of the renewable fuel, feedstock(s) used to make it, and the production process.
(3)The Agency will review the technical justification and assign an appropriate Equivalence Value to the renewable fuel based on the procedure in this paragraph (d).
(4)For biogas, the Equivalence Value is 1.0, and 77,550 Btu of biogas is equivalent to 1 gallon of renewable fuel. §§ 80.1116 through 80.1124 [Reserved] 8. Sections 80.1116 through 80.1124 are reserved. 9. Sections 80.1125 through 80.1132 are added to read as follows: Subpart K—Renewable Fuel Standard Sec. 80.1125 Renewable Identification Numbers (RINs). 80.1126 How are RINs generated and assigned to batches of renewable fuel by renewable fuel producers or importers? 80.1127 How are RINs used to demonstrate compliance? 80.1128 General requirements for RIN distribution. 80.1129 Requirements for separating RINs from volumes of renewable fuel. 80.1130 Requirements for exporters of renewable fuels. 80.1131 Treatment of invalid RINs. 80.1132 Reported spillage of renewable fuel. § 80.1125 Renewable Identification Numbers (RINs). Each RIN is a 38 character numeric code of the following form: KYYYYCCCCFFFFFBBBBBRRDSSSSSSSSEEEEEEEE
(a)K is a number identifying the type of RIN as follows:
(1)K has the value of 1 when the RIN is assigned to a volume of renewable fuel pursuant to §§ 80.1126(e) and 80.1128(a).
(2)K has the value of 2 when the RIN has been separated from a volume of renewable fuel pursuant to § 80.1126(e)(4) or § 80.1129.
(b)YYYY is the calendar year in which the batch of renewable fuel was produced or imported. YYYY also represents the year in which the RIN was originally generated.
(c)CCCC is the registration number assigned according to § 80.1150 to the producer or importer of the batch of renewable fuel.
(d)FFFFF is the registration number assigned according to § 80.1150 to the facility at which the batch of renewable fuel was produced or imported.
(e)BBBBB is a serial number assigned to the batch which is chosen by the producer or importer of the batch such that no two batches have the same value in a given calendar year.
(f)RR is a number representing the equivalence value of the renewable fuel as specified in § 80.1115 and multiplied by 10 to produce the value for RR.
(g)D is a number identifying the type of renewable fuel, as follows:
(1)D has the value of 1 if the renewable fuel can be categorized as cellulosic biomass ethanol as defined in § 80.1101(a).
(2)D has the value of 2 if the renewable fuel cannot be categorized as cellulosic biomass ethanol as defined in § 80.1101(a).
(h)SSSSSSSS is a number representing the first gallon-RIN associated with a batch of renewable fuel.
(i)EEEEEEEE is a number representing the last gallon-RIN associated with a batch of renewable fuel. EEEEEEEE will be identical to SSSSSSSS if the batch-RIN represents a single gallon-RIN. Assign the value of EEEEEEEE as described in § 80.1126. § 80.1126 How are RINs generated and assigned to batches of renewable fuel by renewable fuel producers or importers?
(a)*Regional applicability.*
(1)Except as provided in paragraph
(b)of this section, a RIN must be assigned by a renewable fuel producer or importer to every batch of renewable fuel produced by a facility located in the contiguous 48 states of the United States, or imported into the contiguous 48 states.
(2)If the Administrator approves a petition of Alaska, Hawaii, or a United States territory to opt-in to the renewable fuel program under the provisions in § 80.1143, then the requirements of paragraph (a)(1) of this section shall also apply to renewable fuel produced or imported into that state or territory beginning in the next calendar year.
(b)*Volume threshold* . Renewable fuel producers located within the United States that produce less than 10,000 gallons of renewable fuel each year, and importers that import less than 10,000 gallons of renewable fuel each year, are not required to generate and assign RINs to batches of renewable fuel. Such producers and importers are also exempt from the registration, reporting, and recordkeeping requirements of §§ 80.1150-80.1152. However, for such producers and importers that voluntarily generate and assign RINs, all the requirements of this subpart apply.
(c)*Definition of batch.* For the purposes of this section and § 80.1125, a “batch of renewable fuel” is a volume of renewable fuel that has been assigned a unique RIN code BBBBB within a calendar year by the producer or importer of the renewable fuel in accordance with the provisions of this section and § 80.1125.
(1)The number of gallon-RINs generated for a batch of renewable fuel may not exceed 99,999,999.
(2)A batch of renewable fuel cannot represent renewable fuel produced or imported in excess of one calendar month.
(d)*Generation of RINs.*
(1)Except as provided in paragraph
(b)of this section, the producer or importer of a batch of renewable fuel must generate RINs for that batch, including any renewable fuel contained in imported gasoline.
(2)A producer or importer of renewable fuel may generate RINs for volumes of renewable fuel that it owns on September 1, 2007.
(3)A party generating a RIN shall specify the appropriate numerical values for each component of the RIN in accordance with the provisions of § 80.1125 and this paragraph (d).
(4)Except as provided in paragraph (d)(6) of this section, the number of gallon-RINs that shall be generated for a given batch of renewable fuel shall be equal to a volume calculated according to the following formula: V <sup>RIN</sup> = EV * V <sup>s</sup> Where: V <sup>RIN</sup> = RIN volume, in gallons, for use determining the number of gallon-RINs that shall be generated. EV = Equivalence value for the renewable fuel per § 80.1115. V <sup>s</sup> = Standardized volume of the batch of renewable fuel at 60 °F, in gallons, calculated in accordance with paragraph (d)(7) of this section.
(5)Multiple gallon-RINs generated to represent a given volume of renewable fuel can be represented by a single batch-RIN through the appropriate designation of the RIN volume codes SSSSSSSS and EEEEEEEE.
(i)The value of SSSSSSSS in the batch-RIN shall be 00000001 to represent the first gallon-RIN associated with the volume of renewable fuel.
(ii)The value of EEEEEEEE in the batch-RIN shall represent the last gallon-RIN associated with the volume of renewable fuel, based on the RIN volume determined pursuant to paragraph (d)(4) of this section.
(i)For renewable crude-based renewable fuels produced in a facility or unit that coprocesses renewable crudes and fossil fuels, the number of gallon-RINs that shall be generated for a given batch of renewable fuel shall be equal to the gallons of renewable crude used rather than the gallons of renewable fuel produced.
(ii)Parties that produce renewable crude-based renewable fuels in a facility or unit that coprocesses renewable crudes and fossil fuels may submit a petition to the Agency requesting the use of volumes of renewable fuel produced as the basis for the number of gallon-RINs, pursuant to paragraph (d)(4) of this section.
(7)*Standardization of volumes.* In determining the standardized volume of a batch of renewable fuel for purposes of generating RINs under this paragraph (d), the batch volumes shall be adjusted to a standard temperature of 60 °F.
(i)For ethanol, the following formula shall be used: V <sup>s,e</sup> = V <sup>a,e</sup> * (−0.0006301 * T + 1.0378) Where: V <sup>s,e</sup> = Standardized volume of ethanol at 60 °F, in gallons. V <sup>a,e</sup> = Actual volume of ethanol, in gallons. T = Actual temperature of the batch, in °F.
(ii)For biodiesel (mono alkyl esters), the following formula shall be used: V <sup>s,b</sup> = V <sup>a,b</sup> * (−0.0008008 * T + 1.0480) Where: V <sup>s,b</sup> = Standardized volume of biodiesel at 60 °F, in gallons. V <sup>a,b</sup> = Actual volume of biodiesel, in gallons. T = Actual temperature of the batch, in °F.
(iii)For other renewable fuels, an appropriate formula commonly accepted by the industry shall be used to standardize the actual volume to 60 °F. Formulas used must be reported to the Agency, and may be reviewed for appropriateness.
(i)A party is prohibited from generating RINs for a volume of renewable fuel that it produces if:
(A)The renewable fuel has been produced from a chemical conversion process that uses another renewable fuel as a feedstock; and
(B)The renewable fuel used as a feedstock was produced by another party.
(ii)Any RINs that the party acquired with renewable fuel used as a feedstock shall be assigned to the new renewable fuel that was made with that feedstock.
(e)*Assignment of RINs to batches.*
(1)Except as provided in paragraph (e)(4) of this section, the producer or importer of renewable fuel must assign all RINs generated to volumes of renewable fuel.
(2)A RIN is assigned to a volume of renewable fuel when ownership of the RIN is transferred along with the transfer of ownership of the volume of renewable fuel, pursuant to § 80.1128(a).
(3)All assigned RINs shall have a K code value of 1.
(4)*RINs not assigned to batches.*
(i)If a party produces or imports a batch of cellulosic biomass ethanol or waste-derived ethanol having an equivalence value of 2.5, that party must assign at least one gallon-RIN to each gallon of cellulosic biomass ethanol or waste-derived ethanol, representing the first 1.0 portion of the Equivalence Value.
(ii)Any remaining gallon-RINs generated for the cellulosic biomass ethanol or waste-derived ethanol which represent the remaining 1.5 portion of the Equivalence Value may remain unassigned.
(iii)The producer or importer of cellulosic biomass ethanol or waste-derived ethanol shall designate the K code as 2 for all unassigned RINs. § 80.1127 How are RINs used to demonstrate compliance?
(a)*Renewable volume obligations.*
(1)Except as specified in paragraph
(b)of this section, each party that is obligated to meet the Renewable Volume Obligation under § 80.1107, or each party that is an exporter of renewable fuels that is obligated to meet a Renewable Volume Obligation under § 80.1130, must demonstrate pursuant to § 80.1152(a)(1) that it has taken ownership of sufficient RINs to satisfy the following equation: ( Σ RINNUM) <sup>i</sup> + ( Σ RINNUM) <sup>i−1</sup> = RVO <sup>i</sup> Where: ( Σ RINNUM) <sup>i</sup> = Sum of all owned gallon-RINs that were generated in year i and are being applied towards the RVO <sup>i,</sup> in gallons. ( Σ RINNUM) <sup>i−1</sup> = Sum of all owned gallon-RINs that were generated in year i−1 and are being applied towards the RVO <sup>i,</sup> in gallons. RVO <sup>i</sup> = The Renewable Volume Obligation for the obligated party or renewable fuel exporter for calendar year i, in gallons, pursuant to § 80.1107 or § 80.1130.
(2)For compliance for calendar years 2008 and later, the value of ( Σ RINNUM) <sup>i−1</sup> may not exceed a value determined by the following inequality: ( Σ RINNUM) <sup>i−1</sup> ≤ 0.20 × RVO <sup>i</sup>
(3)RINs may only be used to demonstrate compliance with the RVO for the calendar year in which they were generated or the following calendar year. RINs used to demonstrate compliance in one year cannot be used to demonstrate compliance in any other year.
(4)A party may only use a RIN for purposes of meeting the requirements of paragraphs (a)(1) and (a)(2) of this section if that RIN is an unassigned RIN with a K code of 2 obtained in accordance with §§ 80.1126(e)(4), 80.1128, and 80.1129.
(5)The number of gallon-RINs associated with a given batch-RIN that can be used for compliance with the RVO shall be calculated from the following formula: RINNUM = EEEEEEEE−SSSSSSSS + 1 Where: RINNUM = Number of gallon-RINs associated with a batch-RIN, where each gallon-RIN represents one gallon of renewable fuel for compliance purposes. EEEEEEEE = Batch-RIN component identifying the last gallon-RIN associated with the batch-RIN. SSSSSSSS = Batch-RIN component identifying the first gallon-RIN associated with the batch-RIN.
(b)*Deficit carryovers.*
(1)An obligated party or an exporter of renewable fuel that fails to meet the requirements of paragraphs (a)(1) or (a)(2) of this section for calendar year i is permitted to carry a deficit into year i+1 under the following conditions:
(i)The party did not carry a deficit into calendar year i from calendar year i−1.
(ii)The party subsequently meets the requirements of paragraph (a)(1) of this section for calendar year i+1 and carries no deficit into year i+2.
(2)A deficit is calculated according to the following formula: D <sup>i</sup> RVO <sup>i−1</sup> ( Σ RINNUM) <sup>i+1</sup> ( Σ RINNUM) <sup>i−1</sup> Where: D <sup>i</sup> = The deficit, in gallons, generated in calendar year i that must be carried over to year i+1 if allowed to do so pursuant to paragraph (b)(1)(i) of this section. RVO <sup>i</sup> = The Renewable Volume Obligation for the obligated party or renewable fuel exporter for calendar year i, in gallons. ( Σ RINNUM) <sup>i−1</sup> = Sum of all acquired gallon-RINs that were generated in year i and are being applied towards the RVO <sup>i,</sup> in gallons. ( Σ RINNUM) <sup>i−1</sup> = Sum of all acquired gallon-RINs that were generated in year i−1 and are being applied towards the RVO <sup>i,</sup> in gallons. § 80.1128 General requirements for RIN distribution.
(a)*RINs assigned to volumes of renewable fuel.*
(1)*Assigned RIN,* for the purposes of this subpart, means a RIN assigned to a volume of renewable fuel pursuant to § 80.1126(e) with a K code of 1.
(2)Except as provided in § 80.1126(e)(4) and § 80.1129, no party can separate a RIN that has been assigned to a batch pursuant to § 80.1126(e).
(3)An assigned RIN cannot be transferred to another party without simultaneously transferring a volume of renewable fuel to that same party.
(4)No more than 2.5 assigned gallon-RINs with a K code of 1 can be transferred to another party with every gallon of renewable fuel transferred to that same party.
(i)On each of the dates listed in paragraph (a)(5)(v) of this section in any calendar year, the following equation must be satisfied for assigned RINs and volumes of renewable fuel owned by a party: Σ
(RIN)<sup>D</sup> ≤ Σ (V <sup>si</sup> ×EV <sup>i</sup> ) <sup>D</sup> Where: D = Applicable date. Σ
(RIN)<sup>D</sup> = Sum of all assigned gallon-RINs with a K code of 1 that are owned on date D. (V <sup>si</sup> ) <sup>D</sup> = Volume i of renewable fuel owned on date D, standardized to 60 °F, in gallons. EV <sup>i</sup> = Equivalence value representing volume i. Σ (Vsi× EV <sup>i</sup> ) <sup>D</sup> = Sum of all volumes of renewable fuel owned on date D, multiplied by their respective equivalence values.
(ii)The equivalence value EV <sup>i</sup> for use in the equation in paragraph (a)(5)(i) of this section for any volume of ethanol shall be 2.5.
(iii)If the equivalence value for a volume of renewable fuel i can be determined pursuant to § 80.1115 based on its composition, then the appropriate equivalence value shall be used for EV <sup>i</sup> .
(iv)If the equivalence value for a volume of renewable fuel cannot be determined based on its composition, the value of EV <sup>i</sup> shall be 1.0.
(v)The applicable dates are March 31, June 30, September 30, and December 31. For 2007 only, the applicable dates are September 30, and December 31.
(6)*Producers and importers of renewable fuel.*
(i)Except as provided in paragraph (a)(6)(ii) of this section, a producer or importer of renewable fuel must transfer ownership of a number of gallon-RINs with a K code of 1 whenever it transfers ownership of a volume of renewable fuel such that the ratio of gallon-RINs to gallons is equal to the equivalence value for the renewable fuel. Σ
(RIN)/ V <sup>s</sup> = EV Where: Σ
(RIN)= Sum of all gallon-RINs with a K code of 1 which are transferred along with volume V <sup>s</sup> . V <sup>s</sup> = A volume of renewable fuel transferred, standardized to 60 °F, in gallons. EV = Equivalence value assigned to the renewable fuel being transferred.
(ii)A producer or importer of renewable fuel can transfer ownership of a volume of renewable fuel without simultaneously transferring ownership of gallon-RINs having a K code of 1 if it can demonstrate one of the following:
(A)It is a small volume producer exempt from the requirement to generate RINs pursuant to § 80.1126(b); or
(B)The producer or importer received an equivalent volume of renewable fuel from another party without accompanying RINs.
(C)The producer or importer has generated RINs for cellulosic biomass ethanol or waste-derived ethanol having an equivalence value of 2.5, and has chosen to specify as unassigned a number of gallon-RINs pursuant to § 80.1126(e)(4).
(7)Any transfer of ownership of assigned RINs must be documented on product transfer documents generated pursuant to § 80.1153.
(i)The RIN must be recorded on the product transfer document used to transfer ownership of the RIN and the volume to another party; or
(ii)The RIN must be recorded on a separate product transfer document transferred to the same party on the same day as the product transfer document used to transfer ownership of the volume of renewable fuel.
(b)*RINs not assigned to volumes of renewable fuel.*
(1)*Unassigned RIN,* for the purposes of this subpart, means a RIN with a K code of 2 that has been separated from a volume of renewable fuel pursuant to § 80.1126(e)(4) or § 80.1129.
(2)Any party that has registered pursuant to § 80.1150 can hold title to an unassigned RIN.
(3)Unassigned RINs can be transferred from one party to another any number of times.
(4)An unassigned batch-RIN can be divided by its holder into multiple batch-RINs, each representing a smaller number of gallon-RINs, if all of the following conditions are met:
(i)All RIN components other than SSSSSSSS and EEEEEEEE are identical for the original parent and newly formed daughter RINs.
(ii)The sum of the gallon-RINs associated with the multiple daughter batch-RINs is equal to the gallon-RINs associated with the parent batch-RIN. § 80.1129 Requirements for separating RINs from volumes of renewable fuel. (a)(1) Separation of a RIN from a volume of renewable fuel means termination of the assignment of the RIN to a volume of renewable fuel.
(2)RINs that have been separated from volumes of renewable fuel become unassigned RINs subject to the provisions of § 80.1128(b).
(b)A RIN that is assigned to a volume of renewable fuel is separated from that volume only under one of the following conditions:
(1)Except as provided in paragraph (b)(6) of this section, a party that is an obligated party according to § 80.1106 must separate any RINs that have been assigned to a volume of renewable fuel if they own that volume.
(2)Except as provided in paragraph (b)(5) of this section, any party that owns a volume of renewable fuel must separate any RINs that have been assigned to that volume once the volume is blended with gasoline or diesel to produce a motor vehicle fuel.
(3)Any party that exports a volume of renewable fuel must separate any RINs that have been assigned to the exported volume.
(4)Any renewable fuel producer or importer that produces or imports a volume of renewable fuel shall have the right to separate any RINs that have been assigned to that volume if the producer or importer designates the renewable fuel as motor vehicle fuel and the renewable fuel is used as motor vehicle fuel.
(5)RINs assigned to a volume of biodiesel (mono-alkyl ester) can only be separated from that volume pursuant to paragraph (b)(2) of this section if such biodiesel is blended into diesel fuel at a concentration of 80 volume percent biodiesel (mono-alkyl ester) or less.
(i)This paragraph (b)(5) shall not apply to obligated parties or exporters of renewable fuel.
(ii)This paragraph (b)(5) shall not apply to renewable fuel producers meeting the requirements of paragraph (b)(4) of this section.
(6)For RINs that an obligated party generates, the obligated party can only separate such RINs from volumes of renewable fuel if the number of gallon-RINs separated is less than or equal to its annual RVO.
(7)A producer or importer of cellulosic biomass ethanol or waste-derived ethanol can separate a portion of the RINs that it generates pursuant to § 80.1126(e)(4).
(c)The party responsible for separating a RIN from a volume of renewable fuel shall change the K code in the RIN from a value of 1 to a value of 2 prior to transferring the RIN to any other party.
(1)Upon and after separation from a renewable fuel volume, a RIN shall not appear on documentation that is either:
(i)Used to identify title to the volume of renewable fuel; or
(ii)Transferred with the volume of renewable fuel.
(2)Upon and after separation of a RIN from its associated volume, product transfer documents used to transfer ownership of the volume must continue to meet the requirements of § 80.1153(a)(5)(iii).
(e)Any obligated party that uses a renewable fuel in a boiler or heater must retire any RINs associated with that volume of renewable fuel and report the retired RINs in the applicable reports under § 80.1152. § 80.1130 Requirements for exporters of renewable fuels.
(a)Any party that owns any amount of renewable fuel (in its neat form or blended with gasoline or diesel) that is exported from the region described in § 80.1126(a) shall acquire sufficient RINs to offset a Renewable Volume Obligation representing the exported renewable fuel.
(b)*Renewable Volume Obligations.* An exporter of renewable fuel shall determine its Renewable Volume Obligation from the volumes of the renewable fuel exported.
(1)A renewable fuel exporter's total Renewable Volume Obligation shall be calculated according to the following formula: RVO <sup>i</sup> = Σ(VOL <sup>k</sup> * EV <sup>k</sup> ) <sup>i</sup> + D <sup>i-1</sup> Where: RVO <sup>i</sup> = The Renewable Volume Obligation for the exporter for calendar year i, in gallons of renewable fuel. k = A discrete volume of renewable fuel. VOL <sup>k</sup> = The standardized volume of discrete volume k of exported renewable fuel, in gallons, calculated in accordance with § 80.1126(d)(7). EV <sup>k</sup> = The equivalence value associated with discrete volume k. Σ = Sum involving all volumes of renewable fuel exported. D <sup>i-1</sup> = Renewable fuel deficit carryover from the previous year, in gallons. (2)(i) If the equivalence value for a volume of renewable fuel can be determined pursuant to § 80.1115 based on its composition, then the appropriate equivalence value shall be used in the calculation of the exporter's Renewable Volume Obligation.
(ii)If the equivalence value for a volume of renewable fuel cannot be determined, the value of EV <sup>k</sup> shall be 1.0.
(c)Each exporter of renewable fuel must demonstrate compliance with its RVO using RINs it has acquired pursuant to § 80.1127. § 80.1131 Treatment of invalid RINs.
(a)*Invalid RINs.* An invalid RIN is a RIN that is any of the following:
(1)Is a duplicate of a valid RIN.
(2)Was based on volumes that have not been standardized to 60 °F.
(3)Has expired.
(4)Was based on an incorrect equivalence value.
(5)Is deemed invalid under § 80.1167(g).
(6)Does not represent renewable fuel as it is defined in § 80.1101.
(7)Was otherwise improperly generated.
(b)In the case of RINs that are invalid, the following provisions apply:
(1)Invalid RINs cannot be used to achieve compliance with the Renewable Volume Obligation of an obligated party or exporter, regardless of the party's good faith belief that the RINs were valid at the time they were acquired.
(2)Upon determination by any party that RINs owned are invalid, the party must adjust their records, reports, and compliance calculations as necessary to reflect the deletion of the invalid RINs.
(3)Any valid RINs remaining after deleting invalid RINs must first be applied to correct the transfer of invalid RINs to another party before applying the valid RINs to meet the party's Renewable Volume Obligation at the end of the compliance year.
(4)In the event that the same RIN is transferred to two or more parties, all such RINs will be deemed to be invalid, unless EPA in its sole discretion determines that some portion of these RINs is valid. § 80.1132 Reported spillage of renewable fuel.
(a)A reported spillage under paragraph
(d)of this section means a spillage of renewable fuel associated with a requirement by a federal, state or local authority to report the spillage.
(b)Except as provided in paragraph
(c)of this section, in the event of a reported spillage of any volume of renewable fuel, the owner of the renewable fuel must retire a number of gallon-RINs corresponding to the volume of spilled renewable fuel multiplied by its equivalence value.
(1)If the equivalence value for the spilled volume may be determined pursuant to § 80.1115 based on its composition, then the appropriate equivalence value shall be used.
(2)If the equivalence value for a spilled volume of renewable fuel cannot be determined, the equivalence value shall be 1.0.
(c)If the owner of a volume of renewable fuel that is spilled and reported establishes that no RINs were generated to represent the volume, then no gallon-RINs shall be retired.
(d)A RIN that is retired under paragraph
(b)of this section:
(1)Must be reported as a retired RIN in the applicable reports under § 80.1152.
(2)May not be transferred to another party or used by any obligated party to demonstrate compliance with the party's Renewable Volume Obligation. §§ 80.1133 through 80.1140 [Reserved] 10. Sections 80.1133 through 80.1140 are reserved. 11. Sections 80.1141 through 80.1143 are added to read as follows: § 80.1141 Small refinery exemption. (a)(1) Gasoline produced at a refinery by a refiner, or foreign refiner (as defined at § 80.1165(a)), is exempt from the renewable fuel standards of § 80.1105 if that refinery meets the definition of a small refinery under § 80.1101(g) for calendar year 20460.
(2)This exemption shall apply through December 31, 2010, unless a refiner chooses to waive this exemption (as described in paragraph
(f)of this section), or the exemption is extended (as described in paragraph
(e)of this section).
(3)For the purposes of this section, the term “refiner” shall include foreign refiners. (b)(1) The small refinery exemption is effective immediately, except as specified in paragraph (b)(4) of this section.
(2)A refiner owning a small refinery must submit a verification letter to EPA containing all of the following information:
(i)The annual average aggregate daily crude oil throughput for the period January 1, 2004, through December 31, 2004 (as determined by dividing the aggregate throughput for the calendar year by the number 365).
(ii)A letter signed by the president, chief operating or chief executive officer of the company, or his/her designee, stating that the information contained in the letter is true to the best of his/her knowledge, and that the company owned the refinery as of January 1, 2004.
(iii)Name, address, phone number, facsimile number, and e-mail address of a corporate contact person.
(3)Verification letters must be submitted by August 31, 2007, to one of the addresses listed in paragraph
(h)of this section.
(4)For foreign refiners the small refinery exemption shall be effective upon approval, by EPA, of a small refinery application. The application must contain all of the elements required for small refinery verification letters (as specified in paragraph (b)(2) of this section), must satisfy the provisions of § 80.1165(f) through
(h)and (o), and must be submitted by August 31, 2007 to one of the addresses listed in paragraph
(h)of this section.
(c)If EPA finds that a refiner provided false or inaccurate information regarding a refinery's crude throughput (pursuant to paragraph (b)(2)(i) of this section) in its small refinery verification letter, the exemption will be void as of the effective date of these regulations.
(d)If a refiner is complying on an aggregate basis for multiple refineries, any such refiner may exclude from the calculation of its Renewable Volume Obligation (under § 80.1107(a)) gasoline from any refinery receiving the small refinery exemption under paragraph
(a)of this section. (e)(1) The exemption period in paragraph
(a)of this section shall be extended by the Administrator for a period of not less than two additional years if a study by the Secretary of Energy determines that compliance with the requirements of this subpart would impose a disproportionate economic hardship on the small refinery.
(i)A refiner may at any time petition the Administrator for an extension of its small refinery exemption under paragraph
(a)of this section for the reason of disproportionate economic hardship.
(ii)A petition for an extension of the small refinery exemption must specify the factors that demonstrate a disproportionate economic hardship and must provide a detailed discussion regarding the inability of the refinery to produce gasoline meeting the requirements of § 80.1105 and the date the refiner anticipates that compliance with the requirements can be achieved at the small refinery.
(2)The Administrator shall act on such a petition not later than 90 days after the date of receipt of the petition.
(f)At any time, a refiner with an approved small refinery exemption under paragraph
(a)of this section may waive that exemption upon notification to EPA.
(1)A refiner's notice to EPA that it intends to waive its small refinery exemption must be received by November 1 to be effective in the next compliance year.
(2)The waiver will be effective beginning on January 1 of the following calendar year, at which point the gasoline produced at that refinery will be subject to the renewable fuels standard of § 80.1105.
(3)The waiver must be sent to EPA at one of the addresses listed in paragraph
(h)of this section.
(g)A refiner that acquires a refinery from either an approved small refiner (as defined under § 80.1142(a)) or another refiner with an approved small refinery exemption under paragraph
(a)of this section shall notify EPA in writing no later than 20 days following the acquisition.
(h)Verification letters under paragraph
(b)of this section, petitions for small refinery hardship extensions under paragraph
(e)of this section, and small refinery exemption waivers under paragraph
(f)of this section shall be sent to one of the following addresses:
(1)*For U.S. mail:* U.S. EPA—Attn: RFS Program, 6406J, 1200 Pennsylvania Avenue, NW., Washington, DC 20460.
(2)*For overnight or courier services:* U.S. EPA, Attn: RFS Program, 6406J, 1310 L Street, NW., 6th floor, Washington, DC 20005. § 80.1142 What are the provisions for small refiners under the RFS program?
(1)Gasoline produced by a refiner, or foreign refiner (as defined at § 80.1165(a)), is exempt from the renewable fuel standards of § 80.1105 if the refiner or foreign refiner does not meet the definition of a small refinery under § 80.1101(g) but meets all of the following criteria:
(i)The refiner produced gasoline at its refineries by processing crude oil through refinery processing units from January 1, 2004 through December 31, 2004.
(ii)The refiner employed an average of no more than 1,500 people, based on the average number of employees for all pay periods for calendar year 2004 for all subsidiary companies, all parent companies, all subsidiaries of the parent companies, and all joint venture partners.
(iii)The refiner had a corporate-average crude oil capacity less than or equal to 155,000 barrels per calendar day
(bpcd)for 2004.
(2)The small refiner exemption shall apply through December 31, 2010, unless a refiner chooses to waive the exemption (pursuant to paragraph
(h)of this section) prior to that date.
(3)For the purposes of this section, the term “refiner” shall include foreign refiners.
(b)The small refiner exemption is effective immediately, except as provided in paragraph
(d)of this section. Refiners who qualify for the small refiner exemption under paragraph
(a)of this section must submit a verification letter (and any other relevant information) to EPA containing all of the following information for the refiner and for all subsidiary companies, all parent companies, all subsidiaries of the parent companies, and all joint venture partners: (1)(i) A listing of the name and address of each company location where any employee worked for the period January 1, 2004 through December 31, 2004.
(ii)The average number of employees at each location based on the number of employees for each pay period for the period January 1, 2004 through December 31, 2004.
(iii)The type of business activities carried out at each location.
(iv)For joint ventures, the total number of employees includes the combined employee count of all corporate entities in the venture.
(v)For government-owned refiners, the total employee count includes all government employees.
(2)The total corporate crude oil capacity of each refinery as reported to the Energy Information Administration
(EIA)of the U.S. Department of Energy (DOE), for the period January 1, 2004 through December 31, 2004. The information submitted to EIA is presumed to be correct. In cases where a company disagrees with this information, the company may petition EPA with appropriate data to correct the record when the company submits its verification letter.
(3)The verification letter must be signed by the president, chief operating or chief executive officer of the company, or his/her designee, stating that the information is true to the best of his/her knowledge, and that the company owned the refinery as of December 31, 2004.
(4)Name, address, phone number, facsimile number, and e-mail address of a corporate contact person.
(c)Verification letters under paragraph
(b)of this section must be submitted by September 1, 2007.
(d)For foreign refiners the small refiner exemption shall be effective upon approval, by EPA, of a small refiner application. The application must contain all of the elements required for small refiner verification letters (as specified in paragraphs (b)(1), (b)(3), and (b)(4) of this section), must demonstrate compliance with the crude oil capacity criterion of paragraph (a)(1)(iii) of this section, must satisfy the provisions of § 80.1165(f) through
(h)and (o), and must be submitted by September 1, 2007 to one of the addresses listed in paragraph
(j)of this section.
(e)A refiner who qualifies as a small refiner under this section and subsequently fails to meet all of the qualifying criteria as set out in paragraph
(a)of this section will have its small refiner exemption terminated effective January 1 of the next calendar year; however, disqualification shall not apply in the case of a merger between two approved small refiners.
(f)If EPA finds that a refiner provided false or inaccurate information in its small refiner status verification letter under this subpart, the small refiner's exemption will be void as of the effective date of these regulations.
(g)If a small refiner is complying on an aggregate basis for multiple refineries, the refiner may exempt the refineries from the calculation of its Renewable Volume Obligation under § 80.1107.
(1)A refiner may, at any time, waive the small refiner exemption under paragraph
(a)of this section upon notification to EPA.
(2)A refiner's notice to EPA that it intends to waive the small refiner exemption must be received by November 1 in order for the waiver to be effective for the following calendar year. The waiver will be effective beginning on January 1 of the following calendar year, at which point the refiner will be subject to the renewable fuel standard of § 80.1105.
(3)The waiver must be sent to EPA at one of the addresses listed in paragraph
(j)of this section.
(i)Any refiner that acquires a refinery from another refiner with approved small refiner status under paragraph
(a)of this section shall notify EPA in writing no later than 20 days following the acquisition.
(j)Verification letters under paragraph
(b)of this section and small refiner exemption waivers under paragraph
(h)of this section shall be sent to one of the following addresses:
(1)*For U.S. Mail:* U.S. EPA—Attn: RFS Program, 6406J, 1200 Pennsylvania Avenue, NW., Washington, DC 20460.
(2)*For overnight or courier services:* U.S. EPA, Attn: RFS Program, 6406J, 1310 L Street, NW., 6th floor, Washington, DC 20005. § 80.1143 What are the opt-in provisions for noncontiguous states and territories?
(a)A noncontiguous state or United States territory may petition the Administrator to opt-in to the program requirements of this subpart.
(b)The Administrator will approve the petition if it meets the provisions of paragraphs
(c)and
(d)of this section.
(c)The petition must be signed by the Governor of the state or his authorized representative (or the equivalent official of the territory). (d)(1) A petition submitted under this section must be received by the Agency by November 1 for the state or territory to be included in the RFS program in the next calendar year.
(2)A petition submitted under this section should be sent to either of the following addresses:
(i)*For U.S. Mail:* U.S. EPA—Attn: RFS Program, 6406J, 1200 Pennsylvania Avenue, NW., Washington, DC 20460.
(ii)*For overnight or courier services:* U.S. EPA, Attn: RFS Program, 6406J, 1310 L Street, NW., 6th floor, Washington, DC 20005.
(e)Upon approval of the petition by the Administrator:
(1)EPA shall calculate the standard for the following year, including the total gasoline volume for the State or territory in question.
(2)Beginning on January 1 of the next calendar year, all gasoline refiners and importers in the state or territory for which a petition has been approved shall be obligated parties as defined in § 80.1106.
(3)Beginning on January 1 of the next calendar year, all renewable fuel producers in the State or territory for which a petition has been approved shall, pursuant to § 80.1126(a)(2), be required to generate RINs and assign them to batches of renewable fuel. §§ 80.1144 through 80.1149 [Reserved] 12. Sections 80.1144 through 80.1149 are reserved. 13. Sections 80.1150 through 80.1155 are added to read as follows: Subpart K—Renewable Fuel Standard Sec. 80.1150 What are the registration requirements under the RFS program? 80.1151 What are the recordkeeping requirements under the RFS program? 80.1152 What are the reporting requirements under the RFS program? 80.1153 What are the product transfer document
(PTD)requirements for the RFS program? 80.1154 What are the provisions for renewable fuel producers and importers who produce or import less than 10,000 gallons of renewable fuel per year? 80.1155 What are the additional requirements for a producer of cellulosic biomass ethanol or waste derived ethanol? § 80.1150 What are the registration requirements under the RFS program?
(a)Any obligated party described in § 80.1106 and any exporter of renewable fuel described in § 80.1130 must provide EPA with the information specified for registration under § 80.76, if such information has not already been provided under the provisions of this part. An obligated party or an exporter of renewable fuel must receive EPA-issued identification numbers prior to engaging in any transaction involving RINs. Registration information may be submitted to EPA at any time after promulgation of this rule in the **Federal Register** .
(b)Any importer or producer of a renewable fuel must provide EPA the information specified under § 80.76, if such information has not already been provided under the provisions of this part, and must receive EPA-issued company and facility identification numbers prior to generating or assigning any RINs. Registration information may be submitted to EPA at any time after promulgation of this rule in the **Federal Register** .
(c)Any party who owns or intends to own RINs, but who is not covered by paragraphs
(a)and
(b)of this section, must provide EPA the information specified under § 80.76, if such information has not already been provided under the provisions of this part and must receive an EPA-issued company identification number prior to owning any RINs. Registration information may be submitted to EPA at any time after promulgation of this rule in the **Federal Register** .
(d)Registration shall be on forms, and following policies, established by the Administrator. § 80.1151 What are the recordkeeping requirements under the RFS program?
(a)Beginning September 1, 2007, any obligated party (as described at § 80.1106) or exporter of renewable fuel (as described at § 80.1130) must keep all of the following records:
(1)Product transfer documents consistent with § 80.1153 and associated with the obligated party's activity, if any, as transferor or transferee of renewable fuel.
(2)Copies of all reports submitted to EPA under § 80.1152(a).
(3)Records related to each RIN transaction, which includes all the following:
(i)A list of the RINs owned, purchased, sold, retired or expired.
(ii)The parties involved in each RIN transaction including the transferor, transferee, and any broker or agent.
(iii)The date of the transfer of the RIN(s).
(iv)Additional information related to details of the transaction and its terms.
(4)Records related to the use of RINs (by facility, if applicable) for compliance, which includes all the following:
(i)Methods and variables used to calculate the Renewable Volume Obligation pursuant to § 80.1107 or § 80.1130.
(ii)List of RINs used to demonstrate compliance.
(iii)Additional information related to details of RIN use for compliance.
(b)Beginning September 1, 2007, any producer or importer of a renewable fuel as defined at § 80.1101(d) must keep all of the following records:
(1)Product transfer documents consistent with § 80.1153 and associated with the renewable fuel producer's or importer's activity, if any, as transferor or transferee of renewable fuel.
(2)Copies of all reports submitted to EPA under § 80.1152(b).
(3)Records related to the generation and assignment of RINs for each facility, including all of the following:
(i)Batch volume in gallons.
(ii)Batch number.
(iii)RIN number as assigned under § 80.1126.
(iv)Identification of batches meeting the definition of cellulosic biomass ethanol.
(v)Date of production or import.
(vi)Results of any laboratory analysis of batch chemical composition or physical properties.
(vii)Additional information related to details of RIN generation.
(4)Records related to each RIN transaction, including all of the following:
(i)A list of the RINs owned, purchased, sold, retired or expired.
(ii)The parties involved in each transaction including the transferor, transferee, and any broker or agent.
(iii)The date of the transfer of the RIN(s).
(iv)Additional information related to details of the transaction and its terms.
(5)Records related to the production or importation of any volume of renewable fuel that the renewable fuel producer or importer designates as motor vehicle fuel and the use of the fuel as motor vehicle fuel.
(c)Beginning September 1, 2007, any producer of a renewable fuel defined at § 80.1101(d) must keep verifiable records of the following:
(1)The amount and type of fossil fuel and waste material-derived fuel used in producing on-site thermal energy dedicated to the production of ethanol at plants producing cellulosic biomass ethanol through the displacement of 90 percent or more of the fossil fuel normally used in the production of ethanol, as described at § 80.1101(a)(2).
(2)The amount and type of feedstocks used in producing cellulosic biomass ethanol as defined in § 80.1101(a)(1).
(3)The equivalent amount of fossil fuel (based on reasonable estimates) associated with the use of off-site generated waste heat that is used in the production of ethanol at plants producing cellulosic biomass ethanol through the displacement of 90 percent or more of the fossil fuel normally used in the production of ethanol, as described at § 80.1101(a)(2).
(4)The plot plan and process flow diagram for plants producing cellulosic biomass and waste derived ethanol as defined in § 80.1101(a) and (b), respectively.
(5)The independent third party verification required under § 80.1155 for producers of cellulosic biomass ethanol and waste derived ethanol.
(d)Beginning September 1, 2007, any party, other than those parties covered in paragraphs
(a)and
(b)of this section, that owns RINs must keep all of the following records:
(1)Product transfer documents consistent with § 80.1153 and associated with the party's activity, if any, as transferor or transferee of renewable fuel.
(2)Copies of all reports submitted to EPA under § 80.1152(c).
(3)Records related to each RIN transaction, including all of the following:
(i)A list of the RINs owned, purchased, sold, retired or expired.
(ii)The parties involved in each RIN transaction including the transferor, transferee, and any broker or agent.
(iii)The date of the transfer of the RIN(s).
(iv)Additional information related to details of the transaction and its terms.
(e)The records required under this section and under § 80.1153 shall be kept for five years from the date they were created, except that records related to transactions involving RINs shall be kept for five years from the date of transfer.
(f)On request by EPA, the records required under this section and under § 80.1153 must be made available to the Administrator or the Administrator's authorized representative. For records that are electronically generated or maintained, the equipment or software necessary to read the records shall be made available; or, if requested by EPA, electronic records shall be converted to paper documents. § 80.1152 What are the reporting requirements under the RFS program?
(a)Any obligated party described in § 80.1106 or exporter of renewable fuel described in § 80.1130 must submit to EPA reports according to the schedule, and containing the information, that is set forth in this paragraph (a).
(1)An annual compliance demonstration report for the previous compliance period shall be submitted every February 28, except as noted in paragraph (a)(1)(x) of this section, and shall include all of the following information:
(i)The obligated party's name.
(ii)The EPA company registration number.
(iii)Whether the party is complying on a corporate (aggregate) or facility-by-facility basis.
(iv)The EPA facility registration number, if complying on a facility-by-facility basis.
(v)The production volume of all of the products listed in § 80.1107(c) for the reporting year.
(vi)The renewable volume obligation (RVO), as defined in § 80.1127(a) for obligated parties and § 80.1130(b) for exporters of renewable fuel, for the reporting year.
(vii)Any deficit RVO carried over from the previous year.
(viii)The total current-year gallon-RINs used for compliance.
(ix)The total prior-years gallon-RINs used for compliance.
(x)A list of all RINs used for compliance in the reporting year. For compliance demonstrations covering calendar year 2007 only, this list shall be reported by May 31, 2008. In all subsequent years, this list shall be submitted by February 28.
(xi)Any deficit RVO carried into the subsequent year.
(xii)Any additional information that the Administrator may require.
(2)The quarterly RIN transaction reports required under paragraph (c)(1) of this section.
(3)The quarterly gallon-RIN activity reports required under paragraph (c)(2) of this section.
(4)Reports required under this paragraph
(a)must be signed and certified as meeting all the applicable requirements of this subpart by the owner or a responsible corporate officer of the obligated party.
(b)Any producer or importer of a renewable fuel must, beginning November 30, 2007, submit to EPA reports according to the schedule, and containing the information, that is set forth in this paragraph (b).
(1)A quarterly RIN-generation report for each facility owned by the renewable fuel producer, and each importer, shall be submitted according to the schedule specified in paragraph
(d)of this section, and shall include for the reporting period all of the following information for each batch of renewable fuel produced or imported, where “batch” means a discreet quantity of renewable fuel produced or imported and assigned a unique RIN:
(i)The renewable fuel producer's or importer's name.
(ii)The EPA company registration number.
(iii)The EPA facility registration number.
(iv)The applicable quarterly reporting period.
(v)The RINs generated for each batch according to § 80.1126.
(vi)The production date of each batch.
(vii)The type of renewable fuel of each batch, as defined in § 80.1101(d).
(viii)Information related to the volume of denaturant and applicable equivalence value of each batch.
(ix)The volume of each batch produced or imported.
(x)Any additional information the Administrator may require.
(2)The RIN transaction reports required under paragraph (c)(1) of this section.
(3)The quarterly gallon-RIN activity report required under paragraph (c)(2) of this section.
(4)Reports required under this paragraph
(b)must be signed and certified as meeting all the applicable requirements of this subpart by the owner or a responsible corporate officer of the renewable fuel producer.
(c)Any party, including any party specified in paragraphs
(a)and
(b)of this section, that owns RINs during a reporting period must, beginning November 30, 2007, submit reports to EPA according to the schedule, and containing the information, that is set forth in this paragraph (c).
(1)A RIN transaction report for each RIN transaction shall be submitted by the end of the quarter in which the transaction occurred, according to the schedule specified in paragraph
(d)of this section. Each report shall include all of the following:
(i)The submitting party's name.
(ii)The party's EPA company registration number.
(iii)The party's facility registration number, if the report required under paragraph (c)(2) of this section is submitted on a facility-by-facility basis.
(iv)The applicable quarterly reporting period.
(v)Transaction type (RIN purchase, RIN sale, expired RIN, retired RIN).
(vi)Transaction date.
(vii)For a RIN purchase or sale, the trading partner's name.
(viii)For a RIN purchase or sale, the trading partner's EPA company registration number. For all other transactions, the submitting party's EPA company registration number.
(ix)RIN subject to the transaction.
(x)For a retired RIN, the reason for retiring the RIN ( *e.g.* , reportable spill under § 80.1132, import volume correction under § 80.1166(k), renewable fuel used in boiler or heater under § 80.1129(e), enforcement obligation).
(xi)Any additional information that the Administrator may require.
(2)A quarterly gallon-RIN activity report shall be submitted to EPA according to the schedule specified in paragraph
(d)of this section. Each report shall summarize gallon-RIN activities for the reporting period, separately for RINs separated from a renewable fuel volume and RINs assigned to a renewable fuel volume. A RIN owner with more than one facility may submit the report required under this paragraph for each of its facilities individually, or for all of its facilities in the aggregate. The quarterly gallon-RIN activity report shall include all of the following information:
(i)The submitting party's name.
(ii)The party's EPA company registration number.
(iii)Whether the party is submitting the report required under this paragraph on a corporate (aggregate) or facility-by-facility basis.
(iv)The party's EPA facility registration number, if the report required under this paragraph is submitted on a facility-by-facility basis.
(v)Number of current-year gallon-RINs owned at the start of the quarter.
(vi)Number of prior-years gallon-RINs owned at the start of the quarter.
(vii)The total current-year gallon-RINs purchased.
(viii)The total prior-years gallon-RINs purchased.
(ix)The total current-year gallon-RINs sold.
(x)The total prior-years gallon-RINs sold.
(xi)The total current-year gallon-RINs retired.
(xii)The total prior-years gallon-RINs retired.
(xiii)The total current-year gallon-RINs expired (fourth quarter only).
(xiv)The total prior-years gallon-RINs expired (fourth quarter only).
(xv)Number of current-year gallon-RINs owned at the end of the quarter.
(xvi)Number of prior-years gallon-RINs owned at the end of the quarter.
(xvii)For parties reporting gallon-RIN activity under this paragraph for RINs assigned to a volume of renewable fuel, the volume of renewable fuel (in gallons) owned at the end of the quarter. (xviii) Any additional information that the Administrator may require.
(3)All reports required under this paragraph
(c)must be signed and certified as meeting all the applicable requirements of this subpart by the RIN owner or a responsible corporate officer of the RIN owner.
(d)Quarterly reports shall be submitted to EPA by: May 31st for the first calendar quarter of January through March; August 31st for the second calendar quarter of April through June; November 30th for the third calendar quarter of July through September; and February 28th for the fourth calendar quarter of October through December. For 2007, quarterly reports shall commence on November 30, 2007.
(e)Reports required under this section shall be submitted on forms and following procedures as prescribed by EPA. § 80.1153 What are the product transfer document
(PTD)requirements for the RFS program?
(a)Any time that a person transfers ownership of renewable fuels subject to this subpart, the transferor must provide to the transferee documents identifying the renewable fuel and any assigned RINs which include all of the following information as applicable:
(1)The name and address of the transferor and transferee.
(2)The transferor's and transferee's EPA company registration number.
(3)The volume of renewable fuel that is being transferred.
(4)The date of the transfer.
(5)Whether any RINs are assigned to the volume, as follows:
(i)If the assigned RINs are being transferred on the same PTD used to transfer ownership of the renewable fuel, then the assigned RINs shall be listed on the PTD.
(ii)If the assigned RINs are being transferred on a separate PTD from that which is used to transfer ownership of the renewable fuel, then the PTD which is used to transfer ownership of the renewable fuel shall state the number of gallon-RINs being transferred as well as a unique reference to the PTD which is transferring the assigned RINs.
(iii)If no assigned RINs are being transferred with the renewable fuel, the PTD which is used to transfer ownership of the renewable fuel shall state “No RINs transferred”.
(b)Except for transfers to truck carriers, retailers, or wholesale purchaser-consumers, product codes may be used to convey the information required under paragraphs (a)(1) through (a)(4) of this section if such codes are clearly understood by each transferee. The RIN number required under paragraph (a)(5) of this section must always appear in its entirety. § 80.1154 What are the provisions for renewable fuel producers and importers who produce or import less than 10,000 gallons of renewable fuel per year?
(a)Renewable fuel producers located within the United States that produce less than 10,000 gallons of renewable fuel each year, and importers who import less than 10,000 gallons of renewable fuel each year, are not required to generate RINs or to assign RINs to batches of renewable fuel. Such producers and importers that do not generate and/or assign RINs to batches of renewable fuel are also exempt from all the following requirements of this subpart K, except as stated in paragraph
(b)of this section:
(1)The registration requirements of § 80.1150.
(2)The recordkeeping requirements of § 80.1151.
(3)The reporting requirements of § 80.1152.
(b)Renewable fuel producers and importers who produce or import less than 10,000 gallons of renewable fuel each year and that generate and/or assign RINs to batches of renewable fuel are subject to the provisions of §§ 80.1150 through 80.1152. § 80.1155 What are the additional requirements for a producer of cellulosic biomass ethanol or waste derived ethanol?
(a)A producer of cellulosic biomass ethanol or waste derived ethanol (hereinafter referred to as “ethanol producer” under this section) is required to arrange for an independent third party to review the records required in § 80.1151(c) and provide the ethanol producer with a written verification that the records support a claim that:
(1)The ethanol producer's facility is a facility that has the capability of producing cellulosic biomass ethanol as defined in § 80.1101(a) or waste derived ethanol as defined in § 80.1101(b); and
(2)The ethanol producer produces cellulosic biomass ethanol as defined in § 80.1101(a) or waste derived ethanol as defined in § 80.1101(b).
(b)The verifications required under paragraph
(a)of this section must be conducted by a Professional Chemical Engineer who is based in the United States and is licensed by the appropriate state agency, unless the ethanol producer is a foreign producer subject to § 80.1166.
(c)To be considered an independent third party under paragraph
(a)of this section:
(1)The third party shall not be operated by the ethanol producer or any subsidiary of employee of the ethanol producer.
(2)The third party shall be free from any interest in the ethanol producer's business.
(3)The ethanol producer shall be free from any interest in the third party's business.
(4)Use of a third party that is debarred, suspended, or proposed for debarment pursuant to the Government-wide Debarment and Suspension regulations, 40 CFR part 32, or the Debarment, Suspension and Ineligibility provisions of the Federal Acquisition Regulations, 48 CFR, part 9, subpart 9.4, shall be deemed noncompliance with the requirements of this section.
(d)The ethanol producer must obtain the written verification required under paragraph (a)(1) of this section by February 28 of the year following the first year in which the ethanol producer claims to be producing cellulosic biomass ethanol or waste derived ethanol.
(e)The verification in paragraph (a)(2) of this section is required for each calendar year that the ethanol producer claims to be producing cellulosic biomass ethanol or waste derived ethanol. The ethanol producer must obtain the written verification required under paragraph (a)(2) of this section by February 28 for the previous calendar year.
(f)The ethanol producer must retain records of the verifications required under paragraph
(a)of this section, as required in § 80.1151(c)(5).
(g)The independent third party shall retain all records pertaining to the verification required under this section for a period of five years from the date of creation and shall deliver such records to the Administrator upon request. §§ 80.1156 through 80.1159 [Reserved] 14. Sections 80.1156 through 80.1159 are reserved. 15. Sections 80.1160 and 80.1161 are added to read as follows: § 80.1160 What acts are prohibited under the RFS program?
(a)*Renewable fuels producer or importer violation.* Except as provided in § 80.1154, no person shall produce or import a renewable fuel without assigning the proper RIN value or identifying it by a RIN number as required under § 80.1126.
(b)*RIN generation and transfer violations.* No person shall do any of the following:
(1)Improperly generate a RIN (i.e., generate a RIN for which the applicable renewable fuel volume was not produced).
(2)Create or transfer to any person a RIN that is invalid under § 80.1131.
(3)Transfer to any person a RIN that is not properly identified as required under § 80.1125.
(4)Transfer to any person a RIN with a K code of 1 without transferring an appropriate volume of renewable fuel to the same person on the same day.
(c)*RIN use violations.* No person shall do any of the following:
(1)Fail to acquire sufficient RINs, or use invalid RINs, to meet the party's renewable fuel volume obligation under § 80.1127.
(2)Fail to acquire sufficient RINs to meet the party's renewable fuel volume obligation under § 80.1130.
(3)Use a validly generated RIN to meet the party's renewable fuel volume obligation under § 80.1127, or separate and transfer a validly generated RIN, where the party ultimately uses the renewable fuel volume associated with the RIN in a heater or boiler.
(d)*RIN retention violation.* No person shall retain RINs in violation of the requirements in § 80.1128(a)(5).
(e)*Causing a violation.* No person shall cause another person to commit an act in violation of any prohibited act under this section. § 80.1161 Who is liable for violations under the RFS program?
(a)*Persons liable for violations of prohibited acts.*
(1)Any person who violates a prohibition under § 80.1160(a) through
(d)is liable for the violation of that prohibition.
(2)Any person who causes another person to violate a prohibition under § 80.1160(a) through
(d)is liable for a violation of § 80.1160(e).
(b)*Persons liable for failure to meet other provisions of this subpart.*
(1)Any person who fails to meet a requirement of any provision of this subpart is liable for a violation of that provision.
(2)Any person who causes another person to fail to meet a requirement of any provision of this subpart is liable for causing a violation of that provision.
(c)*Parent corporation liability.* Any parent corporation is liable for any violation of this subpart that is committed by any of its subsidiaries.
(d)*Joint venture liability.* Each partner to a joint venture is jointly and severally liable for any violation of this subpart that is committed by the joint venture operation. § 80.1162 [Reserved] 16. Section 80.1162 is reserved. 17. Sections 80.1163 through 80.1167 are added to read as follows: Subpart K—Renewable Fuel Standard Sec. 80.1163 What penalties apply under the RFS program? 80.1164 What are the attest engagement requirements under the RFS program? 80.1165 What are the additional requirements under this Subpart for a foreign small refiner? 80.1166 What are the additional requirements under this subpart for a foreign producer of cellulosic biomass ethanol or waste derived ethanol? 80.1167 What are the additional requirements under this subpart for a foreign RIN owner? § 80.1163 What penalties apply under the RFS program?
(a)Any person who is liable for a violation under § 80.1161 is subject to a civil penalty of up to $32,500, as specified in sections 205 and 211(d) of the Clean Air Act, for every day of each such violation and the amount of economic benefit or savings resulting from each violation.
(b)Any person liable under § 80.1161(a) for a violation of § 80.1160(c) for failure to meet a renewable volume obligation, or § 80.1160(e) for causing another party to fail to meet a renewable volume obligation, during any averaging period, is subject to a separate day of violation for each day in the averaging period.
(c)Any person liable under § 80.1161(b) for failure to meet, or causing a failure to meet, a requirement of any provision of this subpart is liable for a separate day of violation for each day such a requirement remains unfulfilled. § 80.1164 What are the attest engagement requirements under the RFS program? The requirements regarding annual attest engagements in §§ 80.125 through 80.127, and 80.130, also apply to any attest engagement procedures required under this subpart. In addition to any other applicable attest engagement procedures, the following annual attest engagement procedures are required under this subpart.
(a)The following attest procedures shall be completed for any obligated party as stated in § 80.1106(a) or exporter of renewable fuel that is subject to the renewable fuel standard under § 80.1105:
(1)*Annual compliance demonstration report.*
(i)Obtain and read a copy of the annual compliance demonstration report required under § 80.1152(a)(1) which contains information regarding all the following:
(A)The obligated party's volume of finished gasoline, reformulated gasoline blendstock for oxygenate blending (RBOB), and conventional gasoline blendstock that becomes finished conventional gasoline upon the addition of oxygenate
(CBOB)produced or imported during the reporting year.
(B)Renewable volume obligation (RVO).
(C)RINs used for compliance.
(ii)Obtain documentation of any volumes of renewable fuel used in gasoline during the reporting year; compute and report as a finding the volumes of renewable fuel represented in these documents.
(iii)Compare the volumes of gasoline reported to EPA in the report required under § 80.1152(a)(1) with the volumes, excluding any renewable fuel volumes, contained in the inventory reconciliation analysis under § 80.133.
(iii)Verify that the production volume information in the obligated party's annual summary report required under § 80.1152(a)(1) agrees with the volume information, excluding any renewable fuel volumes, contained in the inventory reconciliation analysis under § 80.133.
(iv)Compute and report as a finding the obligated party's RVO, and any deficit RVO carried over from the previous year or carried into the subsequent year, and verify that the values agree with the values reported to EPA.
(v)Obtain documentation for all RINs used for compliance during the year being reviewed; compute and report as a finding the RIN numbers and year of generation of RINs represented in these documents; and state whether this information agrees with the report to EPA.
(2)*RIN transaction reports.*
(i)Obtain and read copies of a representative sample of all RIN transaction reports required under § 80.1152(a)(2) for the compliance year.
(ii)Obtain contracts or other documents for the representative sample of RIN transactions; compute and report as a finding the transaction types, transaction dates, and RINs traded; and state whether the information agrees with the party's reports to EPA.
(3)*Gallon-RIN activity reports.*
(i)Obtain and read copies of all quarterly gallon-RIN activity reports required under § 80.1152(a)(3) for the compliance year.
(ii)Obtain documentation of total RINs (including current-year RINs and previous-year RINs) owned at the start of the quarter, purchased, used for compliance, sold, expired and retired during the quarter being reviewed, and owned at the end of the quarter; compute and report as a finding the total RINs owned at the start and end of the quarter, purchased, used for compliance, sold, expired and retired as represented in these documents; and state whether this information agrees with the party's reports to EPA.
(b)The following attest procedures shall be completed for any renewable fuel producer or importer:
(1)*RIN-generation reports.*
(i)Obtain and read copies of the quarterly RIN generation reports required under § 80.1152(b)(1) for the compliance year.
(ii)Obtain production data for each renewable fuel batch produced during the year being reviewed; compute and report as a finding the RIN numbers, production dates, types, volumes of denaturant and applicable equivalence values, and production volumes for each batch; and state whether this information agrees with the party's reports to EPA.
(iii)Verify that the proper number of RINs were generated and assigned for each batch of renewable fuel produced, as required under § 80.1126.
(iv)Obtain product transfer documents for each renewable fuel batch produced during the year being reviewed; report as a finding any product transfer document that did not include the RIN for the batch.
(2)*RIN transaction reports.*
(i)Obtain and read copies of a representative sample of the RIN transaction reports required under § 80.1152(b)(2) for the compliance year.
(ii)Obtain contracts or other documents for the representative sample of RIN transactions; compute and report as a finding the transaction types, transaction dates, and the RINs traded; and state whether this information agrees with the party's reports to EPA.
(3)*Gallon-RIN activity reports.*
(i)Obtain and read copies of the quarterly gallon-RIN activity reports required under § 80.1152(b)(3) for the compliance year.
(ii)Obtain documentation of total RINs (including current-year RINs and previous-year RINs) owned at the start of the quarter, purchased, sold, expired and retired during the quarter being reviewed, and owned at the end of the quarter; compute and report as a finding the total RINs owned at the start and end of the quarter, purchased, used for compliance, sold, expired and retired as represented in these documents; and state whether this information agrees with the party's reports to EPA.
(c)The following attest procedures shall be completed for any party other than an obligated party or renewable fuel producer or importer that owns any RINs during a calendar year.
(1)*RIN transaction reports.*
(i)Obtain and read copies of a representative sample of the RIN transaction reports required under § 80.1152(c)(1) for the compliance year.
(ii)Obtain contracts or other documents for the representative sample of RIN transactions; compute and report as a finding the transaction types, transaction dates, and the RINs traded; and state whether this information agrees with the party's reports to EPA.
(2)*Gallon-RIN activity reports.*
(i)Obtain and read copies of the gallon-RIN activity reports required under § 80.1152(c)(2) for the compliance year.
(ii)Obtain documentation of total RINs (including current-year RINs and previous-year RINs) owned at the start of the quarter, purchased, sold, expired and retired during the quarter being reviewed, and owned at the end of the quarter; compute and report as a finding the total RINs owned at the start and end of the quarter, purchased, used for compliance, sold, expired and retired as represented in these documents; and state whether this information agrees with the party's reports to EPA.
(d)The following submission dates apply to the attest engagements required under this section.
(1)For each compliance year, each party subject to the attest engagement requirements under this section shall cause the reports required under this section to be submitted to EPA by May 31 of the year following the compliance year.
(2)For the 2007 compliance year only, the attest engagement required under paragraph
(a)of this section may be submitted to EPA with the attest engagement for the 2008 compliance year. § 80.1165 What are the additional requirements under this subpart for a foreign small refiner?
(a)*Definitions.* The following definitions apply for this subpart:
(1)*Foreign refinery* is a refinery that is located outside the United States, the Commonwealth of Puerto Rico, the U.S. Virgin Islands, Guam, American Samoa, and the Commonwealth of the Northern Mariana Islands (collectively referred to in this section as “the United States”).
(2)*Foreign refiner* is a person that meets the definition of refiner under § 80.2(i) for a foreign refinery.
(3)*RFS-FRGAS* is gasoline produced at a foreign refinery that has received a small refinery exemption under § 80.1141 or a small refiner exemption under § 80.1142 that is imported into the United States.
(4)*Non-RFS-FRGAS* is one of the following:
(i)Gasoline produced at a foreign refinery that has received a small refinery exemption under § 80.1141 or a small refiner exemption under § 80.1142 that is not imported into the United States.
(ii)Gasoline produced at a foreign refinery that has not received a small refinery exemption under § 80.1141 or small refiner exemption under § 80.1142.
(5)A foreign small refiner is a foreign refiner that has received a small refinery exemption under § 80.1141 for one or more of its refineries or a small refiner exemption under § 80.1142.
(b)*General requirements for RFS-FRGAS foreign small refineries and small refiners.*
(1)A foreign small refiner must designate, at the time of production, each batch of gasoline produced at the foreign refinery that is exported for use in the United States as RFS-FRGAS; and
(2)Meet all requirements that apply to refiners who have received a small refinery or small refiner exemption under this subpart.
(c)*Designation, foreign refiner certification, and product transfer documents.*
(1)Any foreign small refiner must designate each batch of RFS-FRGAS as such at the time the gasoline is produced.
(2)On each occasion when RFS-FRGAS is loaded onto a vessel or other transportation mode for transport to the United States, the foreign refiner shall prepare a certification for each batch of RFS-FRGAS that meets all the following requirements:
(i)The certification shall include the report of the independent third party under paragraph
(d)of this section, and all the following additional information:
(A)The name and EPA registration number of the refinery that produced the RFS-FRGAS.
(B)[Reserved]
(ii)The identification of the gasoline as RFS-FRGAS.
(iii)The volume of RFS-FRGAS being transported, in gallons.
(3)On each occasion when any person transfers custody or title to any RFS-FRGAS prior to its being imported into the United States, it must include all the following information as part of the product transfer document information:
(i)Designation of the gasoline as RFS-FRGAS.
(ii)The certification required under paragraph (c)(2) of this section.
(d)*Load port independent testing and refinery identification.*
(1)On each occasion that RFS-FRGAS is loaded onto a vessel for transport to the United States the foreign small refiner shall have an independent third party do all the following:
(i)Inspect the vessel prior to loading and determine the volume of any tank bottoms.
(ii)Determine the volume of RFS-FRGAS loaded onto the vessel (exclusive of any tank bottoms before loading).
(iii)Obtain the EPA-assigned registration number of the foreign refinery.
(iv)Determine the name and country of registration of the vessel used to transport the RFS-FRGAS to the United States.
(v)Determine the date and time the vessel departs the port serving the foreign refinery.
(vi)Review original documents that reflect movement and storage of the RFS-FRGAS from the foreign refinery to the load port, and from this review determine:
(A)The refinery at which the RFS-FRGAS was produced; and
(B)That the RFS-FRGAS remained segregated from Non-RFS-FRGAS and other RFS-FRGAS produced at a different refinery.
(2)The independent third party shall submit a report to:
(i)The foreign small refiner containing the information required under paragraph (d)(1) of this section, to accompany the product transfer documents for the vessel; and
(ii)The Administrator containing the information required under paragraph (d)(1) of this section, within thirty days following the date of the independent third party's inspection. This report shall include a description of the method used to determine the identity of the refinery at which the gasoline was produced, assurance that the gasoline remained segregated as specified in paragraph (j)(1) of this section, and a description of the gasoline's movement and storage between production at the source refinery and vessel loading.
(3)The independent third party must:
(i)Be approved in advance by EPA, based on a demonstration of ability to perform the procedures required in this paragraph (d);
(ii)Be independent under the criteria specified in § 80.65(f)(2)(iii); and
(iii)Sign a commitment that contains the provisions specified in paragraph
(f)of this section with regard to activities, facilities, and documents relevant to compliance with the requirements of this paragraph (d).
(e)*Comparison of load port and port of entry testing.* (1)(i) Any small foreign small refiner and any United States importer of RFS-FRGAS shall compare the results from the load port testing under paragraph
(d)of this section, with the port of entry testing as reported under paragraph
(k)of this section, for the volume of gasoline, except as specified in paragraph (e)(1)(ii) of this section.
(ii)Where a vessel transporting RFS-FRGAS off loads this gasoline at more than one United States port of entry, the requirements of paragraph (e)(1)(i) of this section do not apply at subsequent ports of entry if the United States importer obtains a certification from the vessel owner that the requirements of paragraph (e)(1)(i) of this section were met and that the vessel has not loaded any gasoline or blendstock between the first United States port of entry and the subsequent port of entry.
(2)If the temperature-corrected volumes determined at the port of entry and at the load port differ by more than one percent, the United States importer and the foreign small refiner shall not treat the gasoline as RFS-FRGAS and the importer shall include the volume of gasoline in the importer's RFS compliance calculations.
(f)*Foreign refiner commitments.* Any small foreign small refiner shall commit to and comply with the provisions contained in this paragraph
(f)as a condition to being approved for a small refinery or small refiner exemption under this subpart.
(1)Any United States Environmental Protection Agency inspector or auditor must be given full, complete and immediate access to conduct inspections and audits of the foreign refinery.
(i)Inspections and audits may be either announced in advance by EPA, or unannounced.
(ii)Access will be provided to any location where:
(A)Gasoline is produced;
(B)Documents related to refinery operations are kept; and
(C)RFS-FRGAS is stored or transported between the foreign refinery and the United States, including storage tanks, vessels and pipelines.
(iii)Inspections and audits may be by EPA employees or contractors to EPA.
(iv)Any documents requested that are related to matters covered by inspections and audits must be provided to an EPA inspector or auditor on request.
(v)Inspections and audits by EPA may include review and copying of any documents related to all the following:
(A)The volume of RFS-FRGAS.
(B)The proper classification of gasoline as being RFS-FRGAS or as not being RFS-FRGAS.
(C)Transfers of title or custody to RFS-FRGAS.
(D)Testing of RFS-FRGAS.
(E)Work performed and reports prepared by independent third parties and by independent auditors under the requirements of this section, including work papers.
(vi)Inspections and audits by EPA may include taking interviewing employees.
(vii)Any employee of the foreign refiner must be made available for interview by the EPA inspector or auditor, on request, within a reasonable time period.
(viii)English language translations of any documents must be provided to an EPA inspector or auditor, on request, within 10 working days.
(ix)English language interpreters must be provided to accompany EPA inspectors and auditors, on request.
(2)An agent for service of process located in the District of Columbia shall be named, and service on this agent constitutes service on the foreign refiner or any employee of the foreign refiner for any action by EPA or otherwise by the United States related to the requirements of this subpart.
(3)The forum for any civil or criminal enforcement action related to the provisions of this section for violations of the Clean Air Act or regulations promulgated thereunder shall be governed by the Clean Air Act, including the EPA administrative forum where allowed under the Clean Air Act.
(4)United States substantive and procedural laws shall apply to any civil or criminal enforcement action against the foreign refiner or any employee of the foreign refiner related to the provisions of this section.
(5)Submitting an application for a small refinery or small refiner exemption, or producing and exporting gasoline under such exemption, and all other actions to comply with the requirements of this subpart relating to such exemption constitute actions or activities covered by and within the meaning of the provisions of 28 U.S.C. 1605(a)(2), but solely with respect to actions instituted against the foreign refiner, its agents and employees in any court or other tribunal in the United States for conduct that violates the requirements applicable to the foreign refiner under this subpart, including conduct that violates the False Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
(6)The foreign refiner, or its agents or employees, will not seek to detain or to impose civil or criminal remedies against EPA inspectors or auditors, whether EPA employees or EPA contractors, for actions performed within the scope of EPA employment related to the provisions of this section.
(7)The commitment required by this paragraph
(f)shall be signed by the owner or president of the foreign refiner business.
(8)In any case where RFS-FRGAS produced at a foreign refinery is stored or transported by another company between the refinery and the vessel that transports the RFS-FRGAS to the United States, the foreign refiner shall obtain from each such other company a commitment that meets the requirements specified in paragraphs (f)(1) through (f)(7) of this section, and these commitments shall be included in the foreign refiner's application for a small refinery or small refiner exemption under this subpart.
(g)*Sovereign immunity.* By submitting an application for a small refinery or small refiner exemption under this subpart, or by producing and exporting gasoline to the United States under such exemption, the foreign refiner, and its agents and employees, without exception, become subject to the full operation of the administrative and judicial enforcement powers and provisions of the United States without limitation based on sovereign immunity, with respect to actions instituted against the foreign refiner, its agents and employees in any court or other tribunal in the United States for conduct that violates the requirements applicable to the foreign refiner under this subpart, including conduct that violates the False Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
(h)*Bond posting.* Any foreign refiner shall meet the requirements of this paragraph
(h)as a condition to approval of a small foreign refinery or small foreign refiner exemption under this subpart.
(1)The foreign refiner shall post a bond of the amount calculated using the following equation: Bond = G * $0.01 Where: Bond = amount of the bond in United States dollars. G = the largest volume of gasoline produced at the foreign refinery and exported to the United States, in gallons, during a single calendar year among the most recent of the following calendar years, up to a maximum of five calendar years: The calendar year immediately preceding the date the refinery's application is submitted, the calendar year the application is submitted, and each succeeding calendar year.
(2)Bonds shall be posted by:
(i)Paying the amount of the bond to the Treasurer of the United States;
(ii)Obtaining a bond in the proper amount from a third party surety agent that is payable to satisfy United States administrative or judicial judgments against the foreign refiner, provided EPA agrees in advance as to the third party and the nature of the surety agreement; or
(iii)An alternative commitment that results in assets of an appropriate liquidity and value being readily available to the United States, provided EPA agrees in advance as to the alternative commitment.
(3)Bonds posted under this paragraph
(h)shall:
(i)Be used to satisfy any judicial judgment that results from an administrative or judicial enforcement action for conduct in violation of this subpart, including where such conduct violates the False Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
(ii)Be provided by a corporate surety that is listed in the United States Department of Treasury Circular 570 “Companies Holding Certificates of Authority as Acceptable Sureties on Federal Bonds”; and
(iii)Include a commitment that the bond will remain in effect for at least five years following the end of latest annual reporting period that the foreign refiner produces gasoline pursuant to the requirements of this subpart.
(4)On any occasion a foreign refiner bond is used to satisfy any judgment, the foreign refiner shall increase the bond to cover the amount used within 90 days of the date the bond is used.
(5)If the bond amount for a foreign refiner increases, the foreign refiner shall increase the bond to cover the shortfall within 90 days of the date the bond amount changes. If the bond amount decreases, the foreign refiner may reduce the amount of the bond beginning 90 days after the date the bond amount changes.
(i)*English language reports* . Any document submitted to EPA by a foreign refiner shall be in English language, or shall include an English language translation.
(j)*Prohibitions* .
(1)No person may combine RFS-FRGAS with any Non-RFS-FRGAS, and no person may combine RFS-FRGAS with any RFS-FRGAS produced at a different refinery, until the importer has met all the requirements of paragraph
(k)of this section.
(2)No foreign refiner or other person may cause another person to commit an action prohibited in paragraph (j)(1) of this section, or that otherwise violates the requirements of this section.
(k)*United States importer requirements* . Any United States importer of RFS-FRGAS shall meet the following requirements:
(1)Each batch of imported RFS-FRGAS shall be classified by the importer as being RFS-FRGAS.
(2)Gasoline shall be classified as RFS-FRGAS according to the designation by the foreign refiner if this designation is supported by product transfer documents prepared by the foreign refiner as required in paragraph
(c)of this section. Additionally, the importer shall comply with all requirements of this subpart applicable to importers.
(3)For each gasoline batch classified as RFS-FRGAS, any United States importer shall have an independent third party do all the following:
(i)Determine the volume of gasoline in the vessel.
(ii)Use the foreign refiner's RFS-FRGAS certification to determine the name and EPA-assigned registration number of the foreign refinery that produced the RFS-FRGAS.
(iii)Determine the name and country of registration of the vessel used to transport the RFS-FRGAS to the United States.
(iv)Determine the date and time the vessel arrives at the United States port of entry.
(4)Any importer shall submit reports within 30 days following the date any vessel transporting RFS-FRGAS arrives at the United States port of entry to:
(i)The Administrator containing the information determined under paragraph (k)(3) of this section; and
(ii)The foreign refiner containing the information determined under paragraph (k)(3)(i) of this section, and including identification of the port at which the product was off loaded.
(5)Any United States importer shall meet all other requirements of this subpart for any imported gasoline that is not classified as RFS-FRGAS under paragraph (k)(2) of this section.
(l)*Truck imports of RFS-FRGAS produced at a foreign refinery* .
(1)Any refiner whose RFS-FRGAS is transported into the United States by truck may petition EPA to use alternative procedures to meet all the following requirements:
(i)Certification under paragraph (c)(2) of this section.
(ii)Load port and port of entry testing requirements under paragraphs
(d)and
(e)of this section.
(iii)Importer testing requirements under paragraph (k)(3) of this section.
(2)These alternative procedures must ensure RFS-FRGAS remains segregated from Non-RFS-FRGAS until it is imported into the United States. The petition will be evaluated based on whether it adequately addresses the following:
(i)Provisions for monitoring pipeline shipments, if applicable, from the refinery, that ensure segregation of RFS-FRGAS from that refinery from all other gasoline.
(ii)Contracts with any terminals and/or pipelines that receive and/or transport RFS-FRGAS that prohibit the commingling of RFS-FRGAS with Non-RFS-FRGAS or RFS-FRGAS from other foreign refineries.
(iii)Attest procedures to be conducted annually by an independent third party that review loading records and import documents based on volume reconciliation, or other criteria, to confirm that all RFS-FRGAS remains segregated throughout the distribution system.
(3)The petition described in this section must be submitted to EPA along with the application for a small refinery or small refiner exemption under this subpart.
(m)*Additional attest requirements for importers of RFS-FRGAS* . The following additional procedures shall be carried out by any importer of RFS-FRGAS as part of the attest engagement required for importers under this subpart K.
(1)Obtain listings of all tenders of RFS-FRGAS. Agree the total volume of tenders from the listings to the gasoline inventory reconciliation analysis required in § 80.133(b), and to the volumes determined by the third party under paragraph
(d)of this section.
(2)For each tender under paragraph (m)(1) of this section, where the gasoline is loaded onto a marine vessel, report as a finding the name and country of registration of each vessel, and the volumes of RFS-FRGAS loaded onto each vessel.
(3)Select a sample from the list of vessels identified in paragraph (m)(2) of this section used to transport RFS-FRGAS, in accordance with the guidelines in § 80.127, and for each vessel selected perform the following:
(i)Obtain the report of the independent third party, under paragraph
(d)of this section.
(A)Agree the information in these reports with regard to vessel identification and gasoline volume.
(B)Identify, and report as a finding, each occasion the load port and port of entry volume results differ by more than the amount allowed in paragraph (e)(2) of this section, and determine whether all of the requirements of paragraph (e)(2) of this section have been met.
(ii)Obtain the documents used by the independent third party to determine transportation and storage of the RFS-FRGAS from the refinery to the load port, under paragraph
(d)of this section. Obtain tank activity records for any storage tank where the RFS-FRGAS is stored, and pipeline activity records for any pipeline used to transport the RFS-FRGAS prior to being loaded onto the vessel. Use these records to determine whether the RFS-FRGAS was produced at the refinery that is the subject of the attest engagement, and whether the RFS-FRGAS was mixed with any Non-RFS-FRGAS or any RFS-FRGAS produced at a different refinery.
(4)Select a sample from the list of vessels identified in paragraph (m)(2) of this section used to transport RFS-FRGAS, in accordance with the guidelines in § 80.127, and for each vessel selected perform the following:
(i)Obtain a commercial document of general circulation that lists vessel arrivals and departures, and that includes the port and date of departure of the vessel, and the port of entry and date of arrival of the vessel.
(ii)Agree the vessel's departure and arrival locations and dates from the independent third party and United States importer reports to the information contained in the commercial document.
(5)Obtain separate listings of all tenders of RFS-FRGAS, and perform the following:
(i)Agree the volume of tenders from the listings to the gasoline inventory reconciliation analysis in § 80.133(b).
(ii)Obtain a separate listing of the tenders under this paragraph (m)(5) where the gasoline is loaded onto a marine vessel. Select a sample from this listing in accordance with the guidelines in § 80.127, and obtain a commercial document of general circulation that lists vessel arrivals and departures, and that includes the port and date of departure and the ports and dates where the gasoline was off loaded for the selected vessels. Determine and report as a finding the country where the gasoline was off loaded for each vessel selected.
(6)In order to complete the requirements of this paragraph (m), an auditor shall:
(i)Be independent of the foreign refiner or importer;
(ii)Be licensed as a Certified Public Accountant in the United States and a citizen of the United States, or be approved in advance by EPA based on a demonstration of ability to perform the procedures required in §§ 80.125 through 80.127, 80.130, 80.1164, and this paragraph (m); and
(iii)Sign a commitment that contains the provisions specified in paragraph
(f)of this section with regard to activities and documents relevant to compliance with the requirements of §§ 80.125 through 80.127, 80.130, 80.1164, and this paragraph (m).
(n)*Withdrawal or suspension of foreign refiner status* . EPA may withdraw or suspend a foreign refiner's small refinery or small refiner exemption where:
(1)A foreign refiner fails to meet any requirement of this section;
(2)A foreign government fails to allow EPA inspections as provided in paragraph (f)(1) of this section;
(3)A foreign refiner asserts a claim of, or a right to claim, sovereign immunity in an action to enforce the requirements in this subpart; or
(4)A foreign refiner fails to pay a civil or criminal penalty that is not satisfied using the foreign refiner bond specified in paragraph
(h)of this section.
(o)*Additional requirements for applications, reports and certificates* . Any application for a small refinery or small refiner exemption, alternative procedures under paragraph
(l)of this section, any report, certification, or other submission required under this section shall be:
(1)Submitted in accordance with procedures specified by the Administrator, including use of any forms that may be specified by the Administrator.
(2)Be signed by the president or owner of the foreign refiner company, or by that person's immediate designee, and shall contain the following declaration: I hereby certify:
(1)That I have actual authority to sign on behalf of and to bind [NAME OF FOREIGN REFINER] with regard to all statements contained herein;
(2)that I am aware that the information contained herein is being Certified, or submitted to the United States Environmental Protection Agency, under the requirements of 40 CFR part 80, subpart K, and that the information is material for determining compliance under these regulations; and
(3)that I have read and understand the information being Certified or submitted, and this information is true, complete and correct to the best of my knowledge and belief after I have taken reasonable and appropriate steps to verify the accuracy thereof. I affirm that I have read and understand the provisions of 40 CFR part 80, subpart K, including 40 CFR 80.1165 apply to [NAME OF FOREIGN REFINER]. Pursuant to Clean Air Act section 113(c) and 18 U.S.C. 1001, the penalty for furnishing false, incomplete or misleading information in this certification or submission is a fine of up to $10,000 U.S., and/or imprisonment for up to five years.” § 80.1166 What are the additional requirements under this subpart for a foreign producer of cellulosic biomass ethanol or waste derived ethanol?
(a)*Foreign producer of cellulosic biomass ethanol or waste derived ethanol* . For purposes of this subpart, a foreign producer of cellulosic biomass ethanol or waste derived ethanol is a person located outside the United States, the Commonwealth of Puerto Rico, the Virgin Islands, Guam, American Samoa, and the Commonwealth of the Northern Mariana Islands (collectively referred to in this section as ”the United States”) that has been approved by EPA to assign RINs to cellulosic biomass ethanol or waste derived ethanol that the foreign producer produces and exports to the United States, hereinafter referred to as a “foreign producer” under this section.
(b)*General requirements* .
(1)An approved foreign producer under this section must meet all requirements that apply to cellulosic biomass ethanol or waste derived ethanol producers under this subpart, except to the extent otherwise specified in paragraph (b)(2) of this section. (2)(i) The independent third party that conducts the facility verification required under § 80.1155(a) must inspect the foreign producer's facility and submit a report to EPA which describes in detail the physical plant and its operation.
(ii)The independent third party that conducts the facility verification required under § 80.1155(a) must be a licensed Professional Engineer in the chemical engineering field, but need not be based in the United States. The independent third party must include documentation of its qualifications as a licensed Professional Engineer in the report required in paragraph (b)(2)(i) of this section.
(iii)The requirements of paragraphs (b)(2)(i) and
(ii)of this section must be met before a foreign entity may be approved as a foreign producer under this subpart.
(c)*Designation, foreign producer certification, and product transfer documents* .
(1)Any approved foreign producer under this section must designate each batch of cellulosic biomass ethanol or waste derived ethanol as “RFS-FRETH” at the time the ethanol is produced.
(2)On each occasion when RFS-FRETH is loaded onto a vessel or other transportation mode for transport to the United States, the foreign producer shall prepare a certification for each batch of RFS-FRETH; the certification shall include the report of the independent third party under paragraph
(d)of this section, and all the following additional information:
(i)The name and EPA registration number of the company that produced the RFS-FRETH.
(ii)The identification of the ethanol as RFS-FRETH.
(iii)The volume of RFS-FRETH being transported, in gallons.
(3)On each occasion when any person transfers custody or title to any RFS-FRETH prior to its being imported into the United States, it must include all the following information as part of the product transfer document information:
(i)Designation of the ethanol as RFS-FRETH.
(ii)The certification required under paragraph (c)(2) of this section.
(d)*Load port independent testing and refinery identification* .
(1)On each occasion that RFS-FRETH is loaded onto a vessel for transport to the United States the foreign producer shall have an independent third party do all the following:
(i)Inspect the vessel prior to loading and determine the volume of any tank bottoms.
(ii)Determine the volume of RFS-FRETH loaded onto the vessel (exclusive of any tank bottoms before loading).
(iii)Obtain the EPA-assigned registration number of the foreign producer.
(iv)Determine the name and country of registration of the vessel used to transport the RFS-FRETH to the United States.
(v)Determine the date and time the vessel departs the port serving the foreign producer.
(vi)Review original documents that reflect movement and storage of the RFS-FRETH from the foreign producer to the load port, and from this review determine the following:
(A)The facility at which the RFS-FRETH was produced.
(B)That the RFS-FRETH remained segregated from Non-RFS-FRETH and other RFS-FRETH produced by a different foreign producer.
(2)The independent third party shall submit a report to the following:
(i)The foreign producer containing the information required under paragraph (d)(1) of this section, to accompany the product transfer documents for the vessel.
(ii)The Administrator containing the information required under paragraph (d)(1) of this section, within thirty days following the date of the independent third party's inspection. This report shall include a description of the method used to determine the identity of the foreign producer facility at which the ethanol was produced, assurance that the ethanol remained segregated as specified in paragraph (j)(1) of this section, and a description of the ethanol's movement and storage between production at the source facility and vessel loading.
(3)The independent third party must:
(i)Be approved in advance by EPA, based on a demonstration of ability to perform the procedures required in this paragraph (d);
(ii)Be independent under the criteria specified in § 80.65(e)(2)(iii); and
(iii)Sign a commitment that contains the provisions specified in paragraph
(f)of this section with regard to activities, facilities and documents relevant to compliance with the requirements of this paragraph (d).
(e)*Comparison of load port and port of entry testing.* (1)(i) Any foreign producer and any United States importer of RFS-FRETH shall compare the results from the load port testing under paragraph
(d)of this section, with the port of entry testing as reported under paragraph
(k)of this section, for the volume of ethanol, except as specified in paragraph (e)(1)(ii) of this section.
(ii)Where a vessel transporting RFS-FRETH off loads the ethanol at more than one United States port of entry, the requirements of paragraph (e)(1)(i) of this section do not apply at subsequent ports of entry if the United States importer obtains a certification from the vessel owner that the requirements of paragraph (e)(1)(i) of this section were met and that the vessel has not loaded any ethanol between the first United States port of entry and the subsequent port of entry. (2)(i) If the temperature-corrected volumes determined at the port of entry and at the load port differ by more than one percent, the number of RINs associated with the ethanol shall be calculated based on the lesser of the two volumes in paragraph (e)(1)(i) of this section.
(ii)Where the port of entry volume is the lesser of the two volumes in paragraph (e)(1)(i) of this section, the importer shall calculate the difference between the number of RINs originally assigned by the foreign producer and the number of RINs calculated under § 80.1126 for the volume of ethanol as measured at the port of entry, and retire that amount of RINs in accordance with paragraph (k)(4) of this section.
(f)*Foreign producer commitments.* Any foreign producer shall commit to and comply with the provisions contained in this paragraph
(f)as a condition to being approved as a foreign producer under this subpart.
(1)Any United States Environmental Protection Agency inspector or auditor must be given full, complete and immediate access to conduct inspections and audits of the foreign producer facility.
(i)Inspections and audits may be either announced in advance by EPA, or unannounced.
(ii)Access will be provided to any location where:
(A)Ethanol is produced;
(B)Documents related to ethanol producer operations are kept; and
(C)RFS-FRETH is stored or transported between the foreign producer and the United States, including storage tanks, vessels and pipelines.
(iii)Inspections and audits may be by EPA employees or contractors to EPA.
(iv)Any documents requested that are related to matters covered by inspections and audits must be provided to an EPA inspector or auditor on request.
(v)Inspections and audits by EPA may include review and copying of any documents related to the following:
(A)The volume of RFS-FRETH.
(B)The proper classification of gasoline as being RFS-FRETH;
(C)Transfers of title or custody to RFS-FRETH.
(D)Work performed and reports prepared by independent third parties and by independent auditors under the requirements of this section, including work papers.
(vi)Inspections and audits by EPA may include interviewing employees.
(vii)Any employee of the foreign producer must be made available for interview by the EPA inspector or auditor, on request, within a reasonable time period.
(viii)English language translations of any documents must be provided to an EPA inspector or auditor, on request, within 10 working days.
(ix)English language interpreters must be provided to accompany EPA inspectors and auditors, on request.
(2)An agent for service of process located in the District of Columbia shall be named, and service on this agent constitutes service on the foreign producer or any employee of the foreign producer for any action by EPA or otherwise by the United States related to the requirements of this subpart.
(3)The forum for any civil or criminal enforcement action related to the provisions of this section for violations of the Clean Air Act or regulations promulgated thereunder shall be governed by the Clean Air Act, including the EPA administrative forum where allowed under the Clean Air Act.
(4)United States substantive and procedural laws shall apply to any civil or criminal enforcement action against the foreign producer or any employee of the foreign producer related to the provisions of this section.
(5)Applying to be an approved foreign producer under this section, or producing or exporting ethanol under such approval, and all other actions to comply with the requirements of this subpart relating to such approval constitute actions or activities covered by and within the meaning of the provisions of 28 U.S.C. 1605(a)(2), but solely with respect to actions instituted against the foreign producer, its agents and employees in any court or other tribunal in the United States for conduct that violates the requirements applicable to the foreign producer under this subpart, including conduct that violates the False Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
(6)The foreign producer, or its agents or employees, will not seek to detain or to impose civil or criminal remedies against EPA inspectors or auditors, whether EPA employees or EPA contractors, for actions performed within the scope of EPA employment related to the provisions of this section.
(7)The commitment required by this paragraph
(f)shall be signed by the owner or president of the foreign producer company.
(8)In any case where RFS-FRETH produced at a foreign producer facility is stored or transported by another company between the refinery and the vessel that transports the RFS-FRETH to the United States, the foreign producer shall obtain from each such other company a commitment that meets the requirements specified in paragraphs (f)(1) through
(7)of this section, and these commitments shall be included in the foreign producer's application to be an approved foreign producer under this subpart.
(g)*Sovereign immunity.* By submitting an application to be an approved foreign producer under this subpart, or by producing and exporting ethanol to the United States under such approval, the foreign producer, and its agents and employees, without exception, become subject to the full operation of the administrative and judicial enforcement powers and provisions of the United States without limitation based on sovereign immunity, with respect to actions instituted against the foreign producer, its agents and employees in any court or other tribunal in the United States for conduct that violates the requirements applicable to the foreign producer under this subpart, including conduct that violates the False Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
(h)*Bond posting.* Any foreign producer shall meet the requirements of this paragraph
(h)as a condition to approval as a foreign producer under this subpart.
(1)The foreign producer shall post a bond of the amount calculated using the following equation: Bond = G * $ 0.01 Where: Bond = amount of the bond in U.S. dollars. G = The largest volume of ethanol produced at the foreign producer's facility and exported to the United States, in gallons, during a single calendar year among the most recent of the following calendar years, up to a maximum of five calendar years: The calendar year immediately preceding the date the refinery's application is submitted, the calendar year the application is submitted, and each succeeding calendar year.
(2)Bonds shall be posted by any of the following methods:
(i)Paying the amount of the bond to the Treasurer of the United States.
(ii)Obtaining a bond in the proper amount from a third party surety agent that is payable to satisfy United States administrative or judicial judgments against the foreign producer, provided EPA agrees in advance as to the third party and the nature of the surety agreement.
(iii)An alternative commitment that results in assets of an appropriate liquidity and value being readily available to the United States provided EPA agrees in advance as to the alternative commitment.
(3)Bonds posted under this paragraph
(h)shall:
(i)Be used to satisfy any judicial judgment that results from an administrative or judicial enforcement action for conduct in violation of this subpart, including where such conduct violates the False Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
(ii)Be provided by a corporate surety that is listed in the United States Department of Treasury Circular 570 ”Companies Holding Certificates of Authority as Acceptable Sureties on Federal Bonds”; and
(iii)Include a commitment that the bond will remain in effect for at least five years following the end of the latest annual reporting period that the foreign producer produces ethanol pursuant to the requirements of this subpart.
(4)On any occasion a foreign producer bond is used to satisfy any judgment, the foreign producer shall increase the bond to cover the amount used within 90 days of the date the bond is used.
(5)If the bond amount for a foreign producer increases, the foreign producer shall increase the bond to cover the shortfall within 90 days of the date the bond amount changes. If the bond amount decreases, the foreign refiner may reduce the amount of the bond beginning 90 days after the date the bond amount changes.
(i)*English language reports.* Any document submitted to EPA by a foreign producer shall be in English language, or shall include an English language translation.
(j)*Prohibitions.*
(1)No person may combine RFS-FRETH with any Non-RFS-FRETH, and no person may combine RFS-FRETH with any RFS-FRETH produced at a different refinery, until the importer has met all the requirements of paragraph
(k)of this section.
(2)No foreign producer or other person may cause another person to commit an action prohibited in paragraph (j)(1) of this section, or that otherwise violates the requirements of this section.
(k)*Requirements for United States importers of RFS-FRETH.* Any United States importer shall meet the following requirements:
(1)Each batch of imported RFS-FRETH shall be classified by the importer as being RFS-FRETH.
(2)Ethanol shall be classified as RFS-FRETH according to the designation by the foreign producer if this designation is supported by product transfer documents prepared by the foreign producer as required in paragraph
(c)of this section.
(3)For each ethanol batch classified as RFS-FRETH, any United States importer shall have an independent third party do all the following:
(i)Determine the volume of gasoline in the vessel.
(ii)Use the foreign producer's RFS-FRETH certification to determine the name and EPA-assigned registration number of the foreign producer that produced the RFS-FRETH.
(iii)Determine the name and country of registration of the vessel used to transport the RFS-FRETH to the United States.
(iv)Determine the date and time the vessel arrives at the United States port of entry.
(4)Where the importer is required to retire RINs under paragraph (e)(2) of this section, the importer must report the retired RINs in the applicable reports under § 80.1152.
(5)Any importer shall submit reports within 30 days following the date any vessel transporting RFS-FRETH arrives at the United States port of entry to the following:
(i)The Administrator containing the information determined under paragraph (k)(3) of this section.
(ii)The foreign producer containing the information determined under paragraph (k)(3)(i) of this section, and including identification of the port at which the product was off loaded, and any RINs retired under paragraph (e)(2) of this section.
(6)Any United States importer shall meet all other requirements of this subpart for any imported ethanol or other renewable fuel that is not classified as RFS-FRETH under paragraph (k)(2) of this section.
(l)*Truck imports of RFS-FRETH produced by a foreign producer* .
(1)Any foreign producer whose RFS-FRETH is transported into the United States by truck may petition EPA to use alternative procedures to meet all the following requirements:
(i)Certification under paragraph (c)(2) of this section.
(ii)Load port and port of entry testing under paragraphs
(d)and
(e)of this section.
(iii)Importer testing under paragraph (k)(3) of this section.
(2)These alternative procedures must ensure RFS-FRETH remains segregated from Non-RFS-FRETH until it is imported into the United States. The petition will be evaluated based on whether it adequately addresses the following:
(i)Contracts with any facilities that receive and/or transport RFS-FRETH that prohibit the commingling of RFS-FRETH with Non-RFS-FRETH or RFS-FRETH from other foreign producers.
(ii)Attest procedures to be conducted annually by an independent third party that review loading records and import documents based on volume reconciliation to confirm that all RFS-FRETH remains segregated.
(3)The petition described in this section must be submitted to EPA along with the application for approval as a foreign producer under this subpart.
(m)*Additional attest requirements for producers of RFS-FRETH.* The following additional procedures shall be carried out by any producer of RFS-FRETH as part of the attest engagement required for renewable fuel producers under this subpart K.
(1)Obtain listings of all tenders of RFS-FRETH. Agree the total volume of tenders from the listings to the volumes determined by the third party under paragraph
(d)of this section.
(2)For each tender under paragraph (m)(1) of this section, where the ethanol is loaded onto a marine vessel, report as a finding the name and country of registration of each vessel, and the volumes of RFS-FRETH loaded onto each vessel.
(3)Select a sample from the list of vessels identified in paragraph (m)(2) of this section used to transport RFS-FRETH, in accordance with the guidelines in § 80.127, and for each vessel selected perform the following:
(i)Obtain the report of the independent third party, under paragraph
(d)of this section, and of the United States importer under paragraph
(k)of this section.
(A)Agree the information in these reports with regard to vessel identification and ethanol volume.
(B)Identify, and report as a finding, each occasion the load port and port of entry volume results differ by more than the amount allowed in paragraph
(e)of this section, and determine whether the importer retired the appropriate amount of RINs as required under paragraph (e)(2) of this section, and submitted the applicable reports under § 80.1152 in accordance with paragraph (k)(4) of this section.
(ii)Obtain the documents used by the independent third party to determine transportation and storage of the RFS-FRETH from the foreign producer's facility to the load port, under paragraph
(d)of this section. Obtain tank activity records for any storage tank where the RFS-FRETH is stored, and activity records for any mode of transportation used to transport the RFS-FRGAS prior to being loaded onto the vessel. Use these records to determine whether the RFS-FRETH was produced at the foreign producer's facility that is the subject of the attest engagement, and whether the RFS-FRETH was mixed with any Non-RFS-FRETH or any RFS-FRETH produced at a different facility.
(4)Select a sample from the list of vessels identified in paragraph (m)(2) of this section used to transport RFS-FRETH, in accordance with the guidelines in § 80.127, and for each vessel selected perform the following:
(i)Obtain a commercial document of general circulation that lists vessel arrivals and departures, and that includes the port and date of departure of the vessel, and the port of entry and date of arrival of the vessel.
(ii)Agree the vessel's departure and arrival locations and dates from the independent third party and United States importer reports to the information contained in the commercial document.
(5)Obtain a separate listing of the tenders under this paragraph (m)(5) where the gasoline is loaded onto a marine vessel. Select a sample from this listing in accordance with the guidelines in § 80.127, and obtain a commercial document of general circulation that lists vessel arrivals and departures, and that includes the port and date of departure and the ports and dates where the ethanol was off loaded for the selected vessels. Determine and report as a finding the country where the ethanol was off loaded for each vessel selected.
(6)In order to complete the requirements of this paragraph
(m)an auditor shall:
(i)Be independent of the foreign producer;
(ii)Be licensed as a Certified Public Accountant in the United States and a citizen of the United States, or be approved in advance by EPA based on a demonstration of ability to perform the procedures required in §§ 80.125 through 80.127, 80.130, 80.1164, and this paragraph (m); and
(iii)Sign a commitment that contains the provisions specified in paragraph
(f)of this section with regard to activities and documents relevant to compliance with the requirements of §§ 80.125 through 80.127, 80.130, 80.1164, and this paragraph (m).
(n)*Withdrawal or suspension of foreign producer approval.* EPA may withdraw or suspend a foreign producer's approval where any of the following occur:
(1)A foreign producer fails to meet any requirement of this section.
(2)A foreign government fails to allow EPA inspections as provided in paragraph (f)(1) of this section.
(3)A foreign producer asserts a claim of, or a right to claim, sovereign immunity in an action to enforce the requirements in this subpart.
(4)A foreign producer fails to pay a civil or criminal penalty that is not satisfied using the foreign producer bond specified in paragraph
(g)of this section.
(o)*Additional requirements for applications, reports and certificates.* Any application for approval as a foreign producer, alternative procedures under paragraph
(l)of this section, any report, certification, or other submission required under this section shall be:
(1)Submitted in accordance with procedures specified by the Administrator, including use of any forms that may be specified by the Administrator.
(2)Signed by the president or owner of the foreign producer company, or by that person's immediate designee, and shall contain the following declaration: I hereby certify:
(1)That I have actual authority to sign on behalf of and to bind [insert name of foreign producer] with regard to all statements contained herein;
(2)that I am aware that the information contained herein is being Certified, or submitted to the United States Environmental Protection Agency, under the requirements of 40 CFR part 80, subpart K, and that the information is material for determining compliance under these regulations; and
(3)that I have read and understand the information being Certified or submitted, and this information is true, complete and correct to the best of my knowledge and belief after I have taken reasonable and appropriate steps to verify the accuracy thereof. I affirm that I have read and understand the provisions of 40 CFR part 80, subpart K, including 40 CFR 80.1165 apply to [insert name of foreign producer]. Pursuant to Clean Air Act section 113(c) and 18 U.S.C. 1001, the penalty for furnishing false, incomplete or misleading information in this certification or submission is a fine of up to $10,000 U.S., and/or imprisonment for up to five years. § 80.1167 What are the additional requirements under this subpart for a foreign RIN owner?
(a)*Foreign RIN owner.* For purposes of this subpart, a foreign RIN owner is a person located outside the United States, the Commonwealth of Puerto Rico, the Virgin Islands, Guam, American Samoa, and the Commonwealth of the Northern Mariana Islands (collectively referred to in this section as “the United States”) that has been approved by EPA to own RINs.
(b)*General Requirement* . An approved foreign RIN owner must meet all requirements that apply to persons who own RINs under this subpart.
(c)*Foreign RIN owner commitments.* Any person shall commit to and comply with the provisions contained in this paragraph
(c)as a condition to being approved as a foreign RIN owner under this subpart.
(1)Any United States Environmental Protection Agency inspector or auditor must be given full, complete and immediate access to conduct inspections and audits of the foreign RIN owner's place of business.
(i)Inspections and audits may be either announced in advance by EPA, or unannounced; and
(ii)Access will be provided to any location where documents related to RINs the foreign RIN owner has obtained, sold, transferred or held are kept.
(iii)Inspections and audits may be by EPA employees or contractors to EPA.
(iv)Any documents requested that are related to matters covered by inspections and audits must be provided to an EPA inspector or auditor on request.
(v)Inspections and audits by EPA may include review and copying of any documents related to the following:
(A)Transfers of title to RINs.
(B)Work performed and reports prepared by independent auditors under the requirements of this section, including work papers.
(vi)Inspections and audits by EPA may include interviewing employees.
(vii)Any employee of the foreign RIN owner must be made available for interview by the EPA inspector or auditor, on request, within a reasonable time period.
(viii)English language translations of any documents must be provided to an EPA inspector or auditor, on request, within 10 working days.
(ix)English language interpreters must be provided to accompany EPA inspectors and auditors, on request.
(2)An agent for service of process located in the District of Columbia shall be named, and service on this agent constitutes service on the foreign RIN owner or any employee of the foreign RIN owner for any action by EPA or otherwise by the United States related to the requirements of this subpart.
(3)The forum for any civil or criminal enforcement action related to the provisions of this section for violations of the Clean Air Act or regulations promulgated thereunder shall be governed by the Clean Air Act, including the EPA administrative forum where allowed under the Clean Air Act.
(4)United States substantive and procedural laws shall apply to any civil or criminal enforcement action against the foreign RIN owner or any employee of the foreign RIN owner related to the provisions of this section.
(5)Submitting an application to be a foreign RIN owner, and all other actions to comply with the requirements of this subpart constitute actions or activities covered by and within the meaning of the provisions of 28 U.S.C. 1605(a)(2), but solely with respect to actions instituted against the foreign RIN owner, its agents and employees in any court or other tribunal in the United States for conduct that violates the requirements applicable to the foreign RIN owner under this subpart, including conduct that violates the False Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
(6)The foreign RIN owner, or its agents or employees, will not seek to detain or to impose civil or criminal remedies against EPA inspectors or auditors, whether EPA employees or EPA contractors, for actions performed within the scope of EPA employment related to the provisions of this section.
(7)The commitment required by this paragraph
(c)shall be signed by the owner or president of the foreign RIN owner business.
(d)*Sovereign immunity.* By submitting an application to be a foreign RIN owner under this subpart, the foreign entity, and its agents and employees, without exception, become subject to the full operation of the administrative and judicial enforcement powers and provisions of the United States without limitation based on sovereign immunity, with respect to actions instituted against the foreign RIN owner, its agents and employees in any court or other tribunal in the United States for conduct that violates the requirements applicable to the foreign RIN owner under this subpart, including conduct that violates the False Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
(e)*Bond posting* . Any foreign entity shall meet the requirements of this paragraph
(d)as a condition to approval as a foreign RIN owner under this subpart.
(1)The foreign entity shall post a bond of the amount calculated using the following equation: Bond = G * $0.01 Where: Bond = amount of the bond in U.S. dollars. G = The total of the number of gallon-RINs the foreign entity expects to sell or transfer during the first calendar year that the foreign entity is a RIN owner, plus the number of gallon-RINs the foreign entity expects to sell or transfer during the next four calendar years. After the first calendar year, the bond amount shall be based on the actual number of gallon-RINs sold or transferred during the current calendar year and the number held at the conclusion of the current averaging year, plus the number of gallon-RINs sold or transferred during the four most recent calendar years preceding the current calendar year. For any year for which there were fewer than four preceding years in which the foreign entity sold or transferred RINs, the bond shall be based on the total of the number of gallon-RINs sold or transferred during the current calendar year and the number held at the end of the current calendar year, plus the number of gallon-RINs sold or transferred during any calendar year preceding the current calendar year, plus the number of gallon-RINs expected to be sold or transferred during subsequent calendar years, the total number of years not to exceed four calendar years in addition to the current calendar year.
(2)Bonds shall be posted by doing any of the following:
(i)Paying the amount of the bond to the Treasurer of the United States.
(ii)Obtaining a bond in the proper amount from a third party surety agent that is payable to satisfy United States administrative or judicial judgments against the foreign RIN owner, provided EPA agrees in advance as to the third party and the nature of the surety agreement.
(iii)An alternative commitment that results in assets of an appropriate liquidity and value being readily available to the United States, provided EPA agrees in advance as to the alternative commitment.
(3)Bonds posted under this paragraph
(e)shall:
(i)Be used to satisfy any judicial judgment that results from an administrative or judicial enforcement action for conduct in violation of this subpart, including where such conduct violates the False Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
(ii)Be provided by a corporate surety that is listed in the United States Department of Treasury Circular 570 “Companies Holding Certificates of Authority as Acceptable Sureties on Federal Bonds”; and
(iii)Include a commitment that the bond will remain in effect for at least five years following the end of latest reporting period in which the foreign RIN owner obtains, sells, transfers or holds RINs.
(4)On any occasion a foreign RIN owner bond is used to satisfy any judgment, the foreign RIN owner shall increase the bond to cover the amount used within 90 days of the date the bond is used.
(f)*English language reports.* Any document submitted to EPA by a foreign RIN owner shall be in English language, or shall include an English language translation.
(g)*Prohibitions.*
(1)A foreign RIN owner is prohibited from obtaining, selling, transferring or holding any RIN that is in excess of the number for which the bond requirements of this section have been satisfied.
(2)Any RIN that is sold, transferred or held that is in excess of the number for which the bond requirements of this section have been satisfied is an invalid RIN under § 80.1131.
(3)Any RIN that is obtained from a person located outside the United States that is not an approved foreign RIN owner under this section is an invalid RIN under § 80.1131.
(4)No foreign RIN owner or other person may cause another person to commit an action prohibited in this paragraph (g), or that otherwise violates the requirements of this section.
(h)*Additional attest requirements for foreign RIN owners.* The following additional requirements apply to any foreign RIN owner as part of the attest engagement required for RIN owners under this subpart K.
(1)The attest auditor must be independent of the foreign RIN owner.
(2)The attest auditor must be licensed as a Certified Public Accountant in the United States and a citizen of the United States, or be approved in advance by EPA based on a demonstration of ability to perform the procedures required in §§ 80.125 through 80.127, 80.130, and 80.1164.
(3)The attest auditor must sign a commitment that contains the provisions specified in paragraph
(c)of this section with regard to activities and documents relevant to compliance with the requirements of §§ 80.125 through 80.127, 80.130, and 80.1164.
(i)*Withdrawal or suspension of foreign RIN owner status.* EPA may withdraw or suspend its approval of a foreign RIN owner where any of the following occur:
(1)A foreign RIN owner fails to meet any requirement of this section, including, but not limited to, the bond requirements.
(2)A foreign government fails to allow EPA inspections as provided in paragraph (c)(1) of this section.
(3)A foreign RIN owner asserts a claim of, or a right to claim, sovereign immunity in an action to enforce the requirements in this subpart.
(4)A foreign RIN owner fails to pay a civil or criminal penalty that is not satisfied using the foreign RIN owner bond specified in paragraph
(e)of this section.
(j)*Additional requirements for applications, reports and certificates.* Any application for approval as a foreign RIN owner, any report, certification, or other submission required under this section shall be:
(1)Submitted in accordance with procedures specified by the Administrator, including use of any forms that may be specified by the Administrator.
(2)Signed by the president or owner of the foreign RIN owner company, or that person's immediate designee, and shall contain the following declaration: I hereby certify:
(1)That I have actual authority to sign on behalf of and to bind [insert name of foreign RIN owner] with regard to all statements contained herein;
(2)that I am aware that the information contained herein is being Certified, or submitted to the United States Environmental Protection Agency, under the requirements of 40 CFR part 80, subpart K, and that the information is material for determining compliance under these regulations; and
(3)that I have read and understand the information being Certified or submitted, and this information is true, complete and correct to the best of my knowledge and belief after I have taken reasonable and appropriate steps to verify the accuracy thereof. I affirm that I have read and understand the provisions of 40 CFR part 80, subpart K, including 40 CFR 80.1167 apply to [insert name of foreign RIN owner]. Pursuant to Clean Air Act section 113(c) and 18 U.S.C. 1001, the penalty for furnishing false, incomplete or misleading information in this certification or submission is a fine of up to $10,000 U.S., and/or imprisonment for up to five years. [FR Doc. E7-7140 Filed 4-30-07; 8:45 am] BILLING CODE 6560-50-P 72 83 Tuesday, May 1, 2007 Proposed Rules Part III Environmental Protection Agency 40 CFR Part 141 Drinking Water: Regulatory Determinations Regarding Contaminants on the Second Drinking Water Contaminant Candidate List—Preliminary Determinations; Proposed Rule ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 141 [EPA-HQ-OW-2007-0068 FRL-8301-3] RIN 2040-AE58 Drinking Water: Regulatory Determinations Regarding Contaminants on the Second Drinking Water Contaminant Candidate List—Preliminary Determinations AGENCY: Environmental Protection Agency (EPA). ACTION: Notice. SUMMARY: The Safe Drinking Water Act (SDWA), as amended in 1996, requires the Environmental Protection Agency
(EPA)to make regulatory determinations on at least five unregulated contaminants and decide whether to regulate these contaminants with a national primary drinking water regulation (NPDWR). SDWA requires that these determinations be made every five years. These unregulated contaminants are typically chosen from a list known as the Contaminant Candidate List (CCL), which SDWA requires the Agency to publish every five years. EPA published the second CCL (CCL 2) in the **Federal Register** on February 24, 2005 (70 FR 9071 (USEPA, 2005a)). This action presents the preliminary regulatory determinations for 11 of the 51 contaminants listed on CCL 2 and describes the supporting rationale for each. The preliminary determination is that an NPDWR is not appropriate for any of the 11 contaminants considered for regulatory determinations. The Agency seeks comment on these 11 preliminary determinations. While the Agency has not made a preliminary determination for perchlorate, this action provides an update on the Agency's evaluation of perchlorate. The Agency requests public comment on the information and the options that the Agency is considering in evaluating perchlorate and welcomes the submission of relevant, new information and/or data that may assist the Agency in its regulatory determination. DATES: Comments must be received on or before July 2, 2007. ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-OW-2007-0068, by one of the following methods: • *http://www.regulations.gov:* Follow the online instructions for submitting comments. • *Mail:* Water Docket, Environmental Protection Agency, Mailcode: 2822T, 1200 Pennsylvania Ave., NW., Washington, DC 20460. • *Hand Delivery:* Water Docket, EPA Docket Center (EPA/DC). Such deliveries are only accepted during the Docket's normal hours of operation, and special arrangements should be made for deliveries of boxed information. *Instructions:* Direct your comments to Docket ID No. EPA-HQ-OW-2007-0068. EPA's policy is that all comments received will be included in the public docket without change and may be made available online at *http://www.regulations.gov,* including any personal information provided, unless the comment includes information claimed to be Confidential Business Information
(CBI)or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through *http://www.regulations.gov.* The *http://www.regulations.gov* Web site is an “anonymous access” system, which means EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an e-mail comment directly to EPA without going through *http://www.regulations.gov* your e-mail address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD-ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses. For additional instructions on submitting comments, go to Unit I.B of the SUPPLEMENTARY INFORMATION section of this document. *Docket:* All documents in the docket are listed in the *http://www.regulations.gov* index. Although listed in the index, some information is not publicly available, *e.g.* , CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in *http://www.regulations.gov* or in hard copy at the Water Docket, EPA/DC, EPA West, Room 3334, 1301 Constitution Ave., NW., Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is
(202)566-1744, and the telephone number for the EPA Docket Center is
(202)566-2426. FOR FURTHER INFORMATION CONTACT: Wynne Miller, Office of Ground Water and Drinking Water, Standards and Risk Management Division, at
(202)564-4887 or e-mail *miller.wynne@epa.gov.* For general information contact the EPA Safe Drinking Water Hotline at
(800)426-4791 or e-mail: *hotline-sdwa@epa.gov.* SUPPLEMENTARY INFORMATION: Abbreviations and Acronyms a. i.—active ingredient <—less than ≤—less than or equal to >—greater than ≥—greater than or equal to μ—microgram, one-millionth of a gram μg/g—micrograms per gram μg/kg—micrograms per kilogram μg/L—micrograms per liter ATSDR—Agency for Toxic Substances and Disease Registry AWWARF—American Water Works Association Research Foundation BMD—bench mark dose BMDL—bench mark dose level BW—body weight for an adult, assumed to be 70 kilograms
(kg)CASRN—Chemical Abstract Services Registry Number CBI—confidential business information CDC—Centers for Disease Control and Prevention ChE—cholinesterase CCL—Contaminant Candidate List CCL 1—EPA's First Contaminant Candidate List CCL 2—EPA's Second Contaminant Candidate List CFR—Code of Federal Regulations CMR—Chemical Monitoring Reform CWS—community water system 1,3-DCP—1,3-dichloropropene DCPA—dimethyl tetrachloroterephthalate (dacthal) DDE—1,1-dichloro-2,2-bis(p-chlorophenyl)ethylene DDT—1,1,1-trichloro-2,2-bis(p-chlorophenyl)ethane DNT—dinitrotoluene DW—dry weight DWEL—drinking water equivalent level DWI—drinking water intake, assumed to be 2 L/day EPA—United States Environmental Protection Agency EPCRA—Emergency Planning and Community Right-to-Know Act EPTC—s-ethyl dipropylthiocarbamate ESA—ethane sulfonic acid FDA—United States Food and Drug Administration FQPA—Food Quality Protection Act FR—Federal Register FW—fresh weight g—gram g/day—grams per day HRL—health reference level IOC—inorganic compound IRIS—Integrated Risk Information System kg—kilogram L—liter LD <sup>50</sup> —an estimate of a single dose that is expected to cause the death of 50 percent of the exposed animals; it is derived from experimental data. LOAEL—lowest-observed-adverse-effect level MAC— *mycobacterium avium intercellulare* MCL—maximum contaminant level MCLG—maximum contaminant level goal mg—milligram, one-thousandth of a gram mg/kg—milligrams per kilogram body weight mg/kg/day—milligrams per kilogram body weight per day mg/L—milligrams per liter mg/m 3 —milligrams per cubic meter MRL—minimum or method reporting limit (depending on the study or suvey cited) MTBE—methyl tertiary butyl ether MTP—monomethyl-2,3,5,6-tetrachloroterephthalate N—number of samples NAS—National Academies of Sciences NAWQA—National Water Quality Assessment (USGS Program) NCEH—National Center for Environmental Health
(CDC)NCFAP—National Center for Food and Agricultural Policy NCI—National Cancer Institute NCWS—non community water system ND—not detected (or non detect) NDWAC—National Drinking Water Advisory Council NHANES—National Health and Nutrition Examination Survey
(CDC)NIRS—National Inorganic and Radionuclide Survey NIS—sodium iodide symporter NOEL—no-observed-effect-level NOAEL—no-observed-adverse-effect level NPS—National Pesticide Survey NQ—not quantifiable (or non quantifiable) NRC—National Research Council NPDWR—National Primary Drinking Water Regulation NTP—National Toxicology Program OA—oxanilic acid OW—Office of Water OPP—Office of Pesticide Programs PCR—Polymerase Chain Reaction PGWDB—pesticides in ground water data base PWS—public water system RED—Reregistration Eligibility Decision RfC—reference concentration RfD—reference dose RSC—relative source contribution SAB—Science Advisory Board SDWA—Safe Drinking Water Act SOC—synthetic organic compound SVOC—semi-volatile organic compound T3—triiodothyronine T4—thyroxine TDS—Total Diet Study
(FDA)Tg-DNT—technical grade DNT TPA—2,3,5,6-tetrachchloroterephthalic acid TRI—Toxics Release Inventory TSH—thyroid stimulating hormone TT—treatment technique UCM—Unregulated Contaminant Monitoring UCMR 1—First Unregulated Contaminant Monitoring Regulation UF—uncertainty factor US—United States of America USDA—United States Department of Agriculture USGS—United States Geological Survey UST—underground storage tanks VOC—volatile organic compound I. General Information A. Does This Action Impose Any Requirements on My Public Water System? B. What Should I Consider as I Prepare My Comments for EPA? II. Purpose, Background and Summary of This Action A. What Is the Purpose of This Action? B. Background on the CCL and Regulatory Determinations C. Summary of the Approach Used To Identify and Evaluate Candidates for Regulatory Determination 2 D. What Are EPA's Preliminary Determinations and What Happens Next? E. Supporting Documentation for EPA's Preliminary Determinations III. What Analyses Did EPA Use To Support the Preliminary Regulatory Determinations? A. Evaluation of Adverse Health Effects B. Evaluation of Contaminant Occurrence and Exposure IV. Preliminary Regulatory Determinations A. Summary of the Preliminary Regulatory Determination B. Contaminant Profiles 1. Boron 2. and 3. Mono- and Di-Acid Degradates of Dimethyl Tetrachloroterephthalate
(DCPA)4. 1,1-Dichloro-2,2-bis( *p* -chlorophenyl) ethylene
(DDE)5. 1,3-Dichloropropene (1,3-DCP; Telone) 6. and 7. 2,4- and 2,6-Dinitrotoluenes (2,4- and 2,6-DNT) 8. s-Ethyl dipropylthiocarbamate
(EPTC)9. Fonofos 10. Terbacil 11. 1,1,2,2-Tetrachloroethane V. What Is the Status of the Agency's Evaluation of Perchlorate? A. Sources of Perchlorate B. Health Effects C. Occurrence in Water, Food, and Humans. D. Occurrence Studies on Perchlorate in Human Urine, Breast Milk, and Amniotic Fluid E. Status of the Preliminary Regulatory Determination for Perchlorate F. What Are the Potential Options for Characterizing Perchlorate Exposure and Proceeding With the Preliminary Regulatory Determination for Perchlorate? G. Next Steps VI. What About the Remaining CCL 2 Contaminants? A. Metolachlor B. Methyl tertiary-butyl ether C. Microbial Contaminants VII. EPA's Next Steps VIII. References I. General Information A. Does This Action Impose Any Requirements on My Public Water System? None of these preliminary regulatory determinations or the final regulatory determinations, when published, will impose any requirements on anyone. Instead, this action notifies interested parties of the availability of EPA's preliminary regulatory determinations for 11 of the 51 contaminants listed on CCL 2 and seeks comment on these preliminary determinations. This action also provides an update on the Agency's review of perchlorate and methyl tertiary butyl ether (MTBE). B. What Should I Consider as I Prepare My Comments for EPA? You may find the following suggestions helpful for preparing your comments: 1. Explain your views as clearly as possible. 2. Describe any assumptions that you used. 3. Provide any technical information and/or data you used that support your views. 4. If you estimate potential burden or costs, explain how you arrived at your estimate. 5. Provide specific examples to illustrate your concerns. 6. Offer alternatives. 7. Make sure to submit your comments by the comment period deadline. 8. To ensure proper receipt by EPA, identify the appropriate docket identification number in the subject line on the first page of your response. It would also be helpful if you provided the name, date, and **Federal Register** citation related to your comments. II. Purpose, Background and Summary of This Action This section briefly summarizes the purpose of this action, the statutory requirements, previous activities related to the Contaminant Candidate List and regulatory determinations, and the approach used and outcome of these preliminary regulatory determinations. A. What Is the Purpose of This Action? The Safe Drinking Water Act (SDWA), as amended in 1996, requires EPA to publish a list of currently unregulated contaminants that may pose risks for drinking water (referred to as the Contaminant Candidate List, or CCL) and to make determinations on whether to regulate at least five contaminants from the CCL with a national primary drinking water regulation (NPDWR) (section 1412(b)(1)). The 1996 SDWA requires the Agency to publish both the CCL and the regulatory determinations every five years. The purpose of this action is to present
(1)EPA's preliminary regulatory determinations for 11 candidates selected from the 51 contaminants listed on the second CCL (CCL 2),
(2)the process and the rationale used to make these determinations, and
(3)a brief summary of the supporting documentation. This action also includes a request for comment(s) on the Agency's preliminary determinations. The 11 regulatory determination contaminants candidates discussed in this action are boron, the dacthal mono- and di-acid degradates, 1,1-dichloro-2,2-bis(p-chlorophenyl)ethylene (DDE), 1,3-dichloropropene, 2,4-dinitrotoluene, 2,6-dinitrotoluene, s-ethyl propylthiocarbamate (EPTC), fonofos, terbacil, and 1,1,2,2-tetrachloroethane. B. Background on the CCL and Regulatory Determinations 1. Statutory Requirements for CCL and Regulatory Determinations. The specific statutory requirements for the CCL and regulatory determinations can be found in SDWA section 1412(b)(1). The 1996 SDWA Amendments require EPA to publish the CCL every five years. The CCL is a list of contaminants that are not subject to any proposed or promulgated NPDWRs, are known or anticipated to occur in public water systems (PWSs), and may require regulation under SDWA. The 1996 SDWA Amendments also direct EPA to determine whether to regulate at least five contaminants from the CCL every five years (within three and one-half years after publication of the final list). In making regulatory determinations, SDWA requires EPA to publish a Maximum Contaminant Level Goal 1
(MCLG)and promulgate an NPDWR 2 for a contaminant if the Administrator determines that: 1 The MCLG is the “maximum level of a contaminant in drinking water at which no known or anticipated adverse effect on the health of persons would occur, and which allows an adequate margin of safety. Maximum contaminant level goals are nonenforceable health goals” (40 CFR 141.2). 2 An NPDWR is a legally enforceable standard that applies to public water systems. An NPDWR sets a legal limit (called a maximum contaminant level or MCL) or specifies a certain treatment technique
(TT)for public water systems for a specific contaminant or group of contaminants.
(a)The contaminant may have an adverse effect on the health of persons;
(b)the contaminant is known to occur or there is a substantial likelihood that the contaminant will occur in public water systems with a frequency and at levels of public health concern; and
(c)In the sole judgment of the Administrator, regulation of such contaminant presents a meaningful opportunity for health risk reduction for persons served by public water systems. If EPA determines that all three of these statutory criteria are met and makes a final determination that a national primary drinking water regulation is needed, the Agency has 24 months to publish a proposed MCLG and NPDWR. After the proposal, the Agency has 18 months to publish and promulgate a final MCLG and NPDWR (SDWA section 1412(b)(1)(E)). 3 3 The statute authorizes a nine month extension of this promulgation date. 2. The First Contaminant Candidate List (CCL 1). Following the 1996 SDWA Amendments, EPA sought input from the National Drinking Water Advisory Council (NDWAC) on the process that should be used to identify contaminants for inclusion on the CCL. For chemical contaminants, the Agency developed screening and evaluation criteria based on recommendations from NDWAC. For microbiological contaminants, NDWAC recommended that the Agency seek external expertise to identify and select potential waterborne pathogens. As a result, the Agency convened a workshop of microbiologists and public health experts who developed criteria for screening and evaluation and subsequently developed an initial list of potential microbiological contaminants. The first CCL process benefited from considerable input from the NDWAC, the scientific community, and the public through stakeholder meetings and the public comments received on the draft CCL published on October 6, 1997 (62 FR 52193 (USEPA, 1997a)). EPA published the final CCL, which contained 50 chemical and 10 microbiological contaminants, on March 2, 1998 (63 FR 10273 (USEPA, 1998a)). A more detailed discussion of how EPA developed CCL 1 can be found in the 1997 and the 1998 **Federal Register** notices (62 FR 52193 (USEPA, 1997a) and 63 FR 10273 (USEPA, 1998a)). 3. The Regulatory Determinations for CCL 1. EPA published its preliminary regulatory determinations for a subset of contaminants listed on CCL 1 on June 3, 2002 (67 FR 38222 (USEPA, 2002a)). The Agency published its final regulatory determinations on July 18, 2003 (68 FR 42898 (USEPA, 2003a)). EPA identified 9 contaminants from the 60 contaminants listed on CCL 1 that had sufficient data and information available to make regulatory determinations. The 9 contaminants were *Acanthamoeba* , aldrin, dieldrin, hexachlorobutadiene, manganese, metribuzin, naphthalene, sodium, and sulfate. The Agency determined that a national primary drinking water regulation was not necessary for any of these 9 contaminants. The Agency issued guidance on *Acanthamoeba* and health advisories for magnesium, sodium, and sulfate. The decision-making process that EPA used to make its regulatory determinations for CCL 1 was based on substantial expert input and recommendations from different groups including stakeholders, the National Research Council
(NRC)and NDWAC. In June 2002, EPA consulted with the Science Advisory Board
(SAB)Drinking Water Committee and requested its review and comment on whether the protocol EPA developed, based on the NDWAC recommendations, was consistently applied and appropriately documented. SAB provided verbal feedback regarding the use of the NRC and NDWAC recommendations in EPA's decision criteria for making its regulatory determinations. SAB recommended that the Agency provide a transparent and clear explanation of the process for making regulatory determinations. The Agency took SAB's recommendation into consideration and further explained the CCL 1 regulatory determination evaluation process in the July 18, 2003 (68 FR 42898 (USEPA, 2003a)) notice and in the supporting documentation. EPA has used the same approach to develop the regulatory determinations discussed in this action. While this action includes a short description of the decision process used to make regulatory determinations (section II.C), a more detailed discussion can be found in the 2002 and the 2003 **Federal Register** notices (67 FR 38222 (USEPA, 2002a) and 68 FR 42898 (USEPA, 2003a)). 4. The Second Contaminant Candidate List (CCL 2). The Agency published its draft CCL 2 **Federal Register** notice on April 2, 2004 (69 FR 17406 (USEPA, 2004a)) and the final CCL 2 **Federal Register** notice on February 24, 2005 (70 FR 9071 (USEPA, 2005a)). The CCL 2 carried forward the 51 remaining chemical and microbial contaminants that were listed on CCL 1. 5. The Regulatory Determinations for CCL 2. This current action discusses EPA's preliminary determinations for 11 of the 51 contaminants listed on the CCL 2. C. Summary of the Approach Used To Identify and Evaluate Candidates for Regulatory Determination 2 Figure 1 provides a brief overview of the process EPA used to identify which CCL 2 contaminants are candidates for regulatory determinations and the SDWA statutory criteria considered in making the regulatory determinations. BILLING CODE 6560-50-P EP01MY07.050 BILLING CODE 6560-50-C In identifying which CCL 2 contaminants are candidates for regulatory determinations, the Agency considered whether sufficient information and/or data were available to characterize the potential health effects and the known/likely occurrence in and exposure from drinking water. With regards to sufficient health effects information/data, the Agency considered whether an Agency-approved health risk assessment 4 was available to identify any potential adverse health effect(s) and derive an estimated level at which adverse health effect(s) are likely to occur. With regards to sufficient occurrence information/data, the Agency considered whether information/data were available to evaluate and give a generally representative idea of known and/or likely occurrence in public water systems. If sufficient information/data were available to characterize adverse human health effects and known/likely occurrence in public water systems, the Agency identified the contaminant as a potential candidate for regulatory determinations. In addition to information/data for health and occurrence, EPA also considered the availability and adequacy of analytical methods (for monitoring) and treatment. 4 Health information used for the regulatory determinations process includes but is not limited to health assessments available from the Agency's Integrated Risk Information System (IRIS), the Agency's Office of Pesticide Programs
(OPP)in a Reregistration Eligibility Decision (RED), the National Academy of Sciences (NAS), and/or the Agency for Toxic Substances and Disease Registry (ATSDR). If EPA chose a contaminant as a candidate for regulatory determination, the Agency used an approach similar to the first regulatory determination process to answer the three statutory criteria (listed in section II.B.1). For the current regulatory determination process, the Agency considered the following in evaluating each of the three statutory criteria.
(1)First statutory criterion—Is the contaminant likely to cause an adverse effect on the health of persons? The Agency evaluated the best available, peer-reviewed assessments and studies to characterize the human health effects that may result from exposure to the contaminant when found in drinking water. Based on this characterization, the Agency estimated a health reference level
(HRL)for each contaminant. Section III.A provides more detailed information about the approach used to evaluate and analyze the health information.
(2)Second statutory criterion—Is the contaminant known or likely to occur in public water systems at a frequency and level of concern? To evaluate known occurrence in PWSs, the Agency compiled, screened, and analyzed data from several occurrence data sets to develop representative occurrence estimates for public drinking water systems. EPA used the HRL estimates for each contaminant as a benchmark against which to conduct an initial evaluation or screening of the occurrence data. For each contaminant, EPA estimated the number of PWSs (and the population served by these PWSs) with detections greater than one-half the HRL (> 1/2 HRL) and greater than the HRL (> HRL). To evaluate the likelihood of a contaminant to occur in drinking water, the Agency considered information on the use and release of a contaminant into the environment and supplemental information on occurrence in water ( *e.g.* , ambient water quality data, State ambient or finished water data, and/or special studies performed by other agencies, organizations and/or entities). Section III.B provides more details on the approach used to analyze the occurrence information/data.
(3)Third statutory criterion—In the sole judgment of the Administrator, does regulation of the contaminant present a meaningful opportunity for health risk reduction for persons served by public water systems? EPA evaluated the potential health effects and the results of the occurrence and exposure estimates (i.e., the population exposed and the sources of exposure) at the health level of concern to determine if regulation presents a meaningful opportunity for health risk reduction. EPA has made a preliminary determination regarding the meaningful opportunity for health risk reduction for 11 contaminants based upon the population exposed to these contaminants at levels of concern. If the answers to all three statutory criteria are affirmative for a particular contaminant, then the Agency makes a determination that a national drinking water regulation is necessary and proceeds to develop an MCLG and a national primary drinking water regulation for that contaminant. It should be noted that this regulatory determination process is independent of the more detailed analyses needed to develop a national primary drinking water regulation. Thus, a decision to regulate is the beginning of the Agency regulatory development process, not the end. If the answer to any of the three statutory criteria is negative, then the Agency makes a determination that a national drinking water regulation is not necessary for that contaminant. D. What Are EPA's Preliminary Determinations and What Happens Next? EPA has made preliminary determinations that no regulatory actions are appropriate for the 11 contaminants evaluated for this second round of regulatory determinations. EPA will make final determinations on these 11 contaminants after a 60-day comment period. EPA is making preliminary regulatory determinations only on those CCL 2 contaminants that have sufficient information to support such a determination at this time. The Agency continues to conduct research and/or to collect information on the remaining CCL 2 contaminants to fill identified data gaps. The Agency is not precluded from taking action when information becomes available and will not necessarily wait until the end of the next regulatory determination cycle before making other regulatory determinations. E. Supporting Documentation for EPA's Preliminary Determinations For this action, EPA prepared several support documents that are available for review and comment in the EPA Water Docket and at *http://www.regulations.gov.* These support documents include: • A comprehensive regulatory support document entitled, “Regulatory Determinations Support Document for Selected Contaminants from the Second Drinking Water Contaminant Candidate List” (CCL 2) (USEPA, 2006a). This support document summarizes the information and data on the physical and chemical properties, uses and environmental release, environmental fate, potential health effects, occurrence and exposure estimates, the preliminary determination for each contaminant candidate, and the Agency's rationale for its determination. The technical health and occurrence support documents listed next served as the basis for the health information and the drinking water occurrence estimates summarized in this comprehensive regulatory support document. • Technical health support documents. These documents address exposure from drinking water and other media, toxicokinetics, hazard identification, and dose-response assessment, and provide an overall characterization of the risk from drinking water for the contaminants considered for regulatory determination. These documents are listed in the reference section as “USEPA, 2006j” through “USEPA, 2006r.” • Technical occurrence support documents (USEPA, 2006b and USEPA, 2006c). These documents include more detailed information about the sources of the data, how EPA assessed the data quality, completeness, and representativeness, and how the data were used to generate estimates of drinking water contaminant occurrence in support of these regulatory determinations. Section III.B.3 provides more information about the title and content of these technical support documents. III. What Analyses Did EPA Use To Support the Preliminary Regulatory Determinations? Sections III.A and B of this action outline the health effects and occurrence/exposure evaluation process EPA used to support these preliminary determinations. A. Evaluation of Adverse Health Effects Section 1412(b)(1)(A)(i) of SDWA requires EPA to determine whether each candidate contaminant may have an adverse effect on public health. This section describes the overall process the Agency used to evaluate health effects information, the approach used to estimate a contaminant HRL (a benchmark against which to conduct the initial evaluation of the occurrence data), and the approach used to identify and evaluate information on hazard and dose-response for the contaminants under consideration. More specific information about the potential for adverse health effects for each contaminant is presented in section IV.B of this action. There are two different approaches to the derivation of an HRL. One approach is used for chemicals that cause cancer and exhibit a linear response to dose and the other applies to noncarcinogens and carcinogens evaluated using a non-linear approach. 1. Use of Carcinogenicity Data for the Derivation of a Health Reference Level. For those contaminants considered to be likely or probable human carcinogens, EPA evaluated data on the mode of action of the chemical to determine the method of low dose extrapolation. When this analysis indicates that a linear low dose extrapolation is appropriate or when data on the mode of action are lacking, EPA uses a low dose linear extrapolation to calculate risk-specific doses. The risk-specific doses are the estimated oral exposures associated with lifetime excess risk levels that range from one cancer in ten thousand (10 −4 ) to one cancer in a million (10 −6 ). The risk-specific doses (expressed as mg/kg of body weight per day) are combined with adult body weight and drinking water consumption data to estimate drinking water concentrations corresponding to this risk range. EPA generally used the one-in-a-million (10 −6 ) cancer risk in the initial screening of the occurrence data for carcinogens evaluated using linear low dose extrapolation. Five of the eleven contaminants discussed in this action had data available to classify them as likely or probable human carcinogens. These five are also the only contaminants for which low dose linear extrapolations were performed. These five are p,p-dichlorodiphenyldichloroethylene (DDE), 1,3-dichloropropene (1,3-DCP or Telone), 2,4-dinitrotoluene, 2,6-dinitrotoluene, and 1,1,2,2-tetrachloroethane. The remaining 6 contaminants have not been identified as known, likely or probable carcinogens. 2. Use of Non-carcinogenic Health Effects Data for Derivation of an HRL. For those chemicals not considered to be carcinogenic to humans, EPA generally calculates a reference dose (RfD). A RfD is an estimate of a daily oral exposure to the human population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during a lifetime. It can be derived from either a “no-observed-adverse-effect level” (NOAEL), a “lowest-observed-adverse-effect level” (LOAEL), or a benchmark dose, with uncertainty factors applied to reflect limitations of the data used. The Agency uses uncertainty factors
(UFs)to address uncertainty resulting from incompleteness of the toxicological database. The individual UFs (usually applied as integers of 1, 3, or 10) are multiplied together and used to derive the RfD from experimental data. Individual UFs are intended to account for:
(1)The variation in sensitivity among the members of the human population ( *i.e.* , intraspecies variability);
(2)the uncertainty in extrapolating animal data to humans ( *i.e.* , interspecies variability);
(3)the uncertainty in extrapolating from data obtained in a study with less-than-lifetime exposure to lifetime exposure ( *i.e.* , extrapolating from subchronic to chronic exposure);
(4)the uncertainty in extrapolating from a LOAEL rather than from a NOAEL; and/or
(5)the uncertainty associated with an incomplete database. For boron, the dacthal
(DCPA)mono and di acid degradates, s-ethyl dipropylthiocarbamate (EPTC), fonofos and terbacil, EPA derived the HRLs using the RfD approach as follows: HRL = [(RfD × BW)/DWI] × RSC Where: RfD = Reference Dose BW = Body Weight for an adult, assumed to be 70 kilograms
(kg)DWI = Drinking Water Intake, assumed to be 2 L/day (90th percentile) RSC = Relative Source Contribution, or the level of exposure believed to result from drinking water when compared to other sources ( *e.g.* , food, ambient air). A 20 percent RSC is being used to estimate the HRL and screen the occurrence data because it is the lowest and most conservative RSC used in the derivation of an MCLG for drinking water. For each of the 6 aforementioned non-carcinogenic compounds for which the Agency has made a preliminary regulatory determination in this action, EPA used the RfD in conjunction with a 20 percent RSC to derive a conservative HRL estimate and perform an initial screening of the drinking water occurrence data. Since the initial screening of the occurrence data at this conservative HRL value resulted in a preliminary negative determination for each of these 6 compounds, the Agency determined that it was not necessary to further evaluate the RSC in making the regulatory determination. As discussed in section IV.B.2 and 3, the HRL for the two dacthal degradates is based on the HRL value derived for the DCPA parent following the guidance provided by EPA's Office of Pesticide Programs. 3. Sources of Data/Information for Health Effects. EPA used the best available peer-reviewed data and analyses in evaluating adverse health effects. Peer-reviewed health-risk assessments were available for all chemicals considered for regulatory determinations from the Agency's Integrated Risk Information System
(IRIS)Program 5 and/or the Office of Pesticide Programs
(OPP)Reregistration Eligibility Decisions (RED). 6 Table 1 summarizes the sources of the health assessment data for each chemical under regulatory determination consideration. The Agency performed a literature search for studies published after the IRIS or OPP health-risk assessment was completed to determine if new information suggested a different outcome. The Agency collected and evaluated any peer-reviewed publications identified through the literature search for their impact on the RfD and/or cancer assessment. In cases where the recent data indicated that a change to the existing RfD or cancer assessment was needed, the updated OW assessment, as described in the health effects support document, was independently peer-reviewed. All quantitative cancer assessments conducted under the Guidelines for Carcinogen Risk Assessment (51 FR 33992 (USEPA, 1986)) were updated using the Guidelines for Carcinogen Risk Assessment (USEPA, 1999a) as directed in the November 2001 (66 FR 59593 (USEPA, 2001a)) **Federal Register** notice. 5 IRIS is an electronic EPA database ( *http://www.epa.gov/iris/index.html* ) containing peer-reviewed information on human health effects that may result from exposure to various chemicals in the environment. These chemical files contain descriptive and quantitative information on hazard identification and dose response, RfDs for chronic noncarcinogenic health effects, as well as slope factors and unit risks for carcinogenic effects. 6 The OPP is required under the Federal Insecticide Fungicide and Rodenticide Act (FIFRA) to review all pesticides registered prior to 1984 and determine whether to reregister them for continued use. The results of the reregistration analysis are included in the REDs. Copies of the REDs are located at the following Web site: *http://cfpub.epa.gov/oppref/rereg/status.cfm?show=rereg* . In March 2005, EPA updated and finalized the Cancer Guidelines and a Supplementary Children's Guidance, which include new considerations for mode of action and added guidelines related to potential risks due to early childhood exposure (USEPA, 2005b; USEPA, 2005c). EPA updated the earlier assessments (based on the 1986 Guidelines) for DDE, the dinitrotoluenes (2,4 and 2,6 as a mixture), and 1,1,2,2-tetrachloroethane following the 1999 Guidelines. None of these chemicals have been determined to have a mutagenic mode of action, which would require an extra factor of safety for children's health protection. Therefore, conducting the cancer evaluation using the 2005 Cancer Guidelines would not result in any change from the assessment updated following the 1999 Guidelines. The cancer assessment for 1,3-dichloropropene was done by OPP and IRIS (USEPA, 1998b and 2000a) under the Proposed Guidelines for Carcinogen Risk Assessment (61 FR 17960 (USEPA, 1996a)). The Administrator (USEPA, 2005d) has directed that current completed assessments can be considered to be scientifically sound based on the guidance used when the assessment was completed until a new assessment is performed by one of the responsible program offices. Table 1.—Sources and Dates of EPA Health Risk Assessments Chemical IRIS Date OPP RED Date Boron X 2004 Dacthal and its mono- and di-acid degradates X 1994 X 1998 1,3-Dichloropropene X 2000 X 1998 DDE X 1988 2,4-Dinitrotoluene X 1990/1992 2,6-Dinitrotoluene * X 1990 EPTC X 1990 X 1999 Fonofos X 1991 ** X 1996 Terbacil X 1989 X 1998 1,1,2,2-Tetrachloroethane X 1986 * Applies to a mixture of 98 percent 2,4-dinitrotoluene and 2 percent 2,6-dinitrotoluene. ** Health Risk Assessment; RED not completed due to pesticide cancellation. As noted in section II.E, EPA has prepared several technical health effects support documents for the contaminants considered for this round of regulatory determinations. These documents address the exposure from drinking water and other media, toxicokinetics, hazard identification, and dose-response assessment, and provide an overall characterization of risk from drinking water. B. Evaluation of Contaminant Occurrence and Exposure EPA used data from several sources to evaluate occurrence and exposure for the 11 contaminants considered in these regulatory determinations. The major or primary sources of the drinking water occurrence data used to support these determinations include the following sources: • The first Unregulated Contaminant Monitoring Regulation (UCMR 1), • The Unregulated Contaminant Monitoring
(UCM)program, and • The National Inorganic and Radionuclide Survey (NIRS). In addition to these primary sources of occurrence data, the Agency also evaluated supplemental sources of occurrence information. Section III.B.1 of this action provides a brief summary of the primary sources of drinking water occurrence data and section III.B.2 provides brief summary descriptions of the supplemental sources of occurrence information and/or data. A summary of the occurrence data and the results or findings for each of the 11 contaminants considered for regulatory determination is presented in Section IV.B, the contaminant profiles section. 1. Primary Data Sources. As previously mentioned, the primary sources of the drinking water occurrence data used to support this action are the UCMR 1, the UCM program, and NIRS. The following sections provide a brief summary of the data sources and the approach used to estimate a given contaminant's occurrence. Table 2 lists the primary data sources the Agency used for each of the 11 contaminants considered for regulatory determinations. Table 2.—Primary Sources of Drinking Water Occurrence Data Used in the Regulatory Determination Process Number Contaminant Primary data sources UCMR 1 List 1 assessment monitoring List 2 screening survey UCM Round 1 cross section Round 2 cross section NIRS 1 Boron 1 X 2 Dacthal mono- and 3 di-acid degradates X 4 DDE X 5 1,3-Dichloropropene 2 X X X 6 2,4-Dinitrotoluene X 7 2,6-Dinitrotoluene X 8 EPTC X 9 Fonofos X 10 Terbacil X 11 1,1,2,2-Tetrachloroethane X X 1 For boron, EPA also considered the results of a study funded by AWWARF (Frey *et al.* , 2004). 2 1,3-Dichloropropene was sampled as a UCM Round 1 and 2 analyte but due to sample degradation concerns the contaminant was re-analyzed using the samples provided by the small systems that participated in the UCMR 1 List 1 Assessment Monitoring. a. *The Unregulated Contaminant Monitoring Regulation.* In 1999, EPA developed the UCMR program in coordination with the CCL and the National Drinking Water Contaminant Occurrence Database
(NCOD)to provide national occurrence information on unregulated contaminants (September 17, 1999, 64 FR 50556 (USEPA, 1999b); March 2, 2000, 65 FR 11372 (USEPA, 2000b); and January 11, 2001, 66 FR 2273 (USEPA, 2001b)). EPA used data from the UCMR 1 program to evaluate occurrence for 9 of the 11 contaminants considered for these regulatory determinations. These 9 contaminants include the dacthal mono- and di-acid degradates, DDE, 1,3-dichloropropene, 2,4-dinitrotoluene, 2,6-dinitrotoluene, EPTC, fonofos, and terbacil. EPA designed the UCMR 1 data collection with three parts (or tiers) primarily based on the availability of analytical methods. Occurrence data for 8 of the 9 contaminants listed in the preceding paragraph are from the first tier of UCMR (also known as UCMR 1 List 1 Assessment Monitoring). Occurrence data for fonofos are from the second tier of UCMR 1 (also known as the UCMR 1 List 2 Screening Survey). EPA has not collected data as part of the third tier due to the lack of adequate analytical methods. The UCMR 1 List 1 Assessment Monitoring was performed for a specified number of chemical contaminants for which analytical methods have been developed. EPA required all large 7 PWSs, plus a statistically representative national sample of 800 small 8 PWSs to conduct Assessment Monitoring. 9 Approximately one-third of the participating small systems were scheduled to monitor for these contaminants during each calendar year from 2001 through 2003. Large systems could conduct one year of monitoring anytime during the 2001-2003 UCMR 1 period. EPA specified a quarterly monitoring schedule for surface water systems and a twice-a-year, six-month interval monitoring schedule for ground water systems. The objective of the UCMR 1 sampling approach for small systems was to collect contaminant occurrence data from a statistically selected, nationally representative sample of small systems. The small system sample was stratified and population-weighted, and included some other sampling adjustments such as allocating a selection of at least 2 systems from each State. With contaminant monitoring data from all large PWSs and a statistical, nationally representative sample of small PWSs, the UCMR 1 List 1 Assessment Monitoring program provides a contaminant occurrence data set suitable for national drinking water estimates. 7 Systems serving more than 10,000 people. 8 Systems serving 10,000 people or fewer. 9 Large and small systems that purchase 100% of their water supply were not required to participate in the UCMR 1 Assessment Monitoring or the UCMR 1 Screening Survey. In total, 370,312 sample results have been collected under the UCMR 1 List 1 Assessment Monitoring program at approximately 3,083 large systems and 797 small systems. Approximately 33,600 samples were collected for each contaminant. The UCMR 1 List 1 Monitoring program included systems from all 50 States, the District of Columbia, 4 U.S. Territories, and Tribal lands in 5 EPA Regions. An additional 3,719 samples were collected for 1,3-DCP at all small systems that conducted UCMR 1 List 1 Assessment Monitoring. In addition to the UCMR 1 List 1 Assessment Monitoring, EPA required monitoring for selected contaminants (including fonofos) for which analytical methods were developed but not widely used. Known as the UCMR 1 List 2 Screening Survey, EPA randomly selected 300 public water systems (120 large and 180 small systems) from the pool of systems required to conduct UCMR 1 List 1 Assessment Monitoring. In total, 29,765 sample results have been collected under the UCMR 1 List 2 Screening Survey from the participating large and small systems. Approximately 2,300 samples were collected for each contaminant. The UCMR 1 List 2 Screening Survey included systems from 48 States, 2 U.S. Territories, and Tribal lands in 1 EPA Region. EPA used the occurrence data from this survey to evaluate fonofos. EPA analyzed the UCMR 1 List 1 Assessment Monitoring and List 2 Screening Survey data to generate the following initial occurrence and exposure summary statistics: • The total number of systems and the total population served by these systems, • The number and percentage of systems with at least 1 observed detection that has a concentration greater than 1/2 the HRL and greater than the HRL (or in some cases greater than or equal to the minimum reporting limit or MRL), and • The number of people and percentage of the population served by systems with at least one observed detection greater than 1/2 the HRL and greater than the HRL (or in some cases greater than or equal to the MRL). 10 10 EPA's support documents (USEPA, 2006a and 2006b) provide summary statistics for the median and 99th percentile concentrations of all analytical detections and detailed occurrence results based on UCMR data according to source water type (surface versus ground water), system size, and State. The initial UCMR 1 summary occurrence statistics for dacthal mono- and di-acid degradates, DDE, 1,3-dichloropropene, 2,4-dinitrotoluene, 2,6-dinitrotoluene, EPTC, fonofos, and terbacil are presented in section IV.B of this action. b. *The Unregulated Contaminant Monitoring Program Rounds 1 and 2.* In 1987, EPA initiated the UCM program to fulfill a 1986 SDWA Amendment that required monitoring of specified unregulated contaminants to gather information on their occurrence in drinking water for future regulatory decision-making purposes. EPA used data from the UCM program to evaluate occurrence for 2 of the 11 contaminants considered for these regulatory determinations. These two contaminants are 1,3-dichloropropene and 1,1,2,2-tetrachloroethane. EPA implemented the UCM program in two phases or rounds. The first round of UCM monitoring generally extended from 1988 to 1992 and is referred to as UCM Round 1 monitoring. The second round of UCM monitoring generally extended from 1993 to 1997 and is referred to as UCM Round 2 monitoring. UCM Round 1 monitored for 34 volatile organic compounds (VOCs), including 1,3-dichloropropene and 1,1,2,2-tetrachloroethane (52 FR 25720 (USEPA, 1987)). UCM Round 2 monitored for 13 synthetic organic compounds (SOCs), sulfate and the same 34 VOCs from UCM Round 1 monitoring (57 FR 31776 (USEPA, 1992a)). The UCM Round 1 database contains contaminant occurrence data from 38 States, Washington, DC, and the U.S. Virgin Islands. The UCM Round 2 database contains data from 34 States and several Tribes. Due to incomplete State data sets, national occurrence estimates based on raw (unedited) UCM Round 1 or Round 2 data could be skewed to low-occurrence or high-occurrence settings (e.g., some States only reported detections). To address potential biases in the data, 11 EPA developed national cross-sections from the UCM Round 1 and Round 2 State data using an approach similar to that used for EPA's 1999 Chemical Monitoring Reform (CMR), the first Six Year Review, and the first CCL Regulatory Determinations. This national cross-section approach was developed to support occurrence analyses and was supported by scientific peer reviewers and stakeholders. This approach identified 24 of the original 38 States from the UCM Round 1 database and 20 of the original 34 States from the UCM Round 2 data base for the national cross-section. 11 The potential bias in the raw UCM data are due to lack of representativeness (since not all States provided UCM data) and incompleteness (since some States that provided data had incomplete data sets). Because UCM Round 1 and Round 2 data represent different time periods and include occurrence data from different States, EPA developed separate national cross-sections for each data set. The UCM Round 1 national cross-section consists of data from 24 States, with approximately 3.3 million total analytical data points from approximately 22,000 unique PWSs. The UCM Round 2 national cross-section consists of data from 20 States, with approximately 3.7 million analytical data points from slightly more than 27,000 unique PWSs. The UCM Round 1 and 2 national cross-sections represent significantly large samples of national occurrence data. Within each cross-section, the actual number of systems and analytical records for each contaminant varies. The support document, “The Analysis of Occurrence Data from the Unregulated Contaminant Monitoring
(UCM)Program and National Inorganics and Radionuclides Survey
(NIRS)in Support of Regulatory Determinations for the Second Drinking Water Contaminant Candidate List” (USEPA, 2006c), provides a description of how the national cross-sections for the Round 1 and Round 2 data sets were developed. EPA constructed the national cross-sections in a way that provides a balance and range of States with varying pollution potential indicators, a wide range of the geologic and hydrologic conditions, and a very large sample of monitoring data points. While EPA recognizes that some limitations exist, the Agency believes that the national cross-sections do provide a reasonable estimate of the overall distribution and the central tendency of contaminant occurrence across the United States. EPA analyzed the UCM Round 1 and 2 National Cross-Section data to generate the following initial occurrence and exposure summary statistics: • The total number of systems and the total population served by these systems, • The number and percentage of systems with at least 1 observed detection that has a concentration greater than 1/2 the HRL and greater than the HRL (or in some cases greater than or equal to the MRL), and • The number of people and percentage of the population served by systems with at least 1 observed detection that has a concentration greater than 1/2 the HRL and greater than the HRL (or in some cases greater than or equal to the MRL). 12 12 EPA's support documents (USEPA, 2006a and 2006c) provide summary statistics for the median and 99th percentile concentrations of all analytical detections and detailed occurrence results based on the UCM Round 1 and 2 Nationals Cross-Sectons according to source water type (surface versus ground water), system size, and State. The initial UCM summary occurrence statistics for 1,3-dichloropropene and 1,1,2,2-tetrachloroethane are presented in section IV.B of this action. c. *National Inorganic and Radionuclide Survey.* In the mid-1980's, EPA conducted the NIRS to provide a statistically representative sample 13 of the national occurrence of inorganic contaminants in community water systems
(CWSs)served by ground water. EPA used data from NIRS, as well as a supplemental survey, to evaluate occurrence for boron. 13 NIRS was designed to provide results that are statistically representative of natioal occurrence at CWSs using ground water sources and is stratified based on system size (population served by the system). Most of the NIRS data are from smaller systems (92 percent from systems serving 3,300 persons or fewer). The NIRS database includes 36 radionuclides and inorganic compounds (IOCs), including boron. The NIRS provides contaminant occurrence data from 989 ground water CWSs covering 49 States (all except Hawaii) and does not include surface water systems. The survey focused on ground water systems, in part because IOCs tend to occur more frequently and at higher concentrations in ground water than in surface water. Each of the 989 randomly selected CWSs was sampled at a single time between 1984 and 1986. EPA analyzed the NIRS data to generate the following occurrence and exposure summary statistics for boron: • The total number of systems and the total population served by these systems, • The number and the percentage of systems with at least 1 detection that has a concentration greater than 1/2 the HRL and greater than the HRL, • The number of people and percentage of the population served by systems with at least 1 observed detection that has a concentration greater than 1/2 the HRL and greater than the HRL. 14 14 EPA's support documents (USEPA, 2006a and 2006c) provide the number and percentage of systems with detections, the 99th percentile concentration of all samples, the 99th percentile concentration of samples with detections, and the median concentration of samples with detections. Similar to the treatment of the UCM cross-section data, the actual values for the NIRS analyses of boron are reported in section IV.B. Because the NIRS data were collected in a randomly designed sample survey, these summary statistics are representative of national occurrence in ground water CWSs. One limitation of the NIRS is a lack of occurrence data for surface water systems. To provide perspective on the occurrence of boron in surface water systems relative to ground water systems, EPA reviewed and took into consideration a recent boron occurrence survey funded by American Water Works Association Research Foundation (AWWARF) (Frey *et al.* , 2004). A short description of the AWWARF study is provided in the supplemental section (section III.B.2) and the results of the AWWARF survey are presented in section IV.B of this action. d. *Presentation of Occurrence Data and Analytical Approach.* As noted previously, the occurrence values and summary statistics presented in this action are the actual data from the UCMR 1, UCM, and NIRS data sets. These occurrence values represent direct counts of the number and percent of systems, and population served by systems, with at least 1 analytical detection above some specified concentration threshold. EPA considered this to be the most straightforward and accurate way to present these data for the regulatory determination process. While both UCMR 1 and UCM data could support more involved statistical modeling to characterize occurrence based on mean (rather than peak) concentrations, EPA chose not to perform this step for the regulatory determinations proposed in this action. EPA believes that presenting the actual results of the occurrence monitoring is straight-forward and the use of an analysis based on peak concentrations provides conservative estimates of occurrence and potential exposure from drinking water. Given that the preliminary determinations for the 11 contaminants discussed in this action are negative, it is not necessary to go beyond the conservative (peak concentration) approach used for this analysis. 2. Supplemental Data. The Agency evaluated several sources of supplemental occurrence information to augment the primary drinking water occurrence data, to evaluate the likelihood of contaminant occurrence, and/or to more fully characterize a contaminant's presence in the environment. Sections II.B.2.a through II.B.2.f provide brief descriptions of the main supplemental information/data sources cited in this action. Summarized occurrence findings from these supplemental sources are presented in Section IV.B, the contaminant profiles section. While the following descriptions cover the more commonly referenced supplemental sources of information/data, they do not include every study and survey cited in the contaminant discussions. A more detailed discussion of the supplemental sources of information/data that EPA evaluated for each contaminant can be found in the comprehensive regulatory determination support document (USEPA, 2006a). a. *USGS NAWQA Information/Data.* The United States Geological Survey
(USGS)collects long-term and nationally consistent data describing water quality in ground water and surface water. In 1991, USGS implemented the National Water-Quality Assessment (NAWQA) Program for 10-year cyclical data collection and data analyses. During the first cycle (1991-2001), the NAWQA program monitored 51 major watersheds and aquifers (study units), which supply more than 60% of the nation's drinking water and water used for agriculture and industry in the U.S. (Hamilton *et al.* , 2004). NAWQA has collected data from over 6,400 surface water and 7,000 ground water sampling points. USGS National Synthesis teams prepare comprehensive analyses of data on topics of particular concern. EPA evaluated information/data from the following USGS National Synthesis reports/projects:
(1)The NAWQA Pesticide National Synthesis Project. In 2003, USGS posted the preliminary results from the first cycle of monitoring for pesticides in streams and ground water. USGS considers these results to be provisional. The results and the data can be accessed at *http://ca.water.usgs.gov/pnsp/.* Data are presented separately for surface water and ground water, as well as bed sediments and biota. In each case, results are subdivided by land use category. Land use categories include agricultural, urban, mixed (deeper aquifers of regional extent in the case of ground water), and undeveloped. In this action, the NAWQA pesticide data for surface water are referenced as Martin *et al.*
(2003)and the ground water data are referenced as Kolpin and Martin (2003).
(2)The National Survey of MTBE and Other VOCs in Community Drinking Water Sources (part of the VOC National Synthesis Project). In 2003, USGS published the survey findings for MTBE, other ether gasoline oxygenates, and other volatile organic compounds
(VOCs)in source water used by CWSs in the United States. The survey was funded by AWWARF and performed by USGS in collaboration with the Metropolitan Water District of Southern California and the Oregon Health and Science University. USGS performed the survey in two independent stages designed to provide representative sampling of all CWSs in the United States (Random Source-Water Survey) and to improve understanding of the temporal variability of MTBE and other compounds in selected water sources (Focused Source-Water Survey). Participating water utilities provided samples that were analyzed for 66 VOCs. The random survey design selected 954 CWSs to be nationally representative of surface and ground waters sources used by CWSs. The focused survey studied source waters from 134 CWSs suspected or known to contain MTBE. The reports/results and data sets from the survey can be accessed at *http://sd.water.usgs.gov/nawqa/vocns/nat_survey.html* . The random survey results can be found in the USGS Water Resources Investigations Report 02-4079, referenced as Grady (2003). The focused survey results can be found in the USGS Water Resources Investigations Report 02-4084, referenced as Delzer and Ivahnenko (2003a). b. *USGS National Highway Runoff Data and Methodology Synthesis.* In addition to the NAWQA project, USGS has prepared additional surveys of national contaminant occurrence. For the National Highway Runoff Data and Methodology Synthesis, USGS conducted a review of 44 studies of semi-volatile organic compounds (SVOCs) and VOCs in runoff conducted since 1970. The USGS Synthesis sought to evaluate data quality parameters for comparison between and among these studies, including documentation of sampling protocols and methods, limits of reporting and detection, and protocols of quality-control and quality-assurance. The complete USGS report is Open-File Report 98-409 and is referenced as Lopes and Dionne (1998). c. *Toxics Release Inventory.* EPA established the Toxics Release Inventory
(TRI)in 1987 in response to section 313 of the Emergency Planning and Community Right-to-Know Act (EPCRA). EPCRA section 313 requires facilities to report to both EPA and the States annual information on toxic chemical releases from facilities that meet reporting criteria. EPCRA section 313 also requires EPA to make this information available to the public through a computer database. This database is accessible through TRI Explorer, which can be accessed at *http://www.epa.gov/triexplorer* . In 1990 Congress passed the Pollution Prevention Act, which required that additional data on waste management and source reduction activities be reported under TRI. The TRI database details not only the types and quantities of toxic chemicals released to the air, water, and land by facilities, but also provides information on the quantities of chemicals sent to other facilities for further management (USEPA, 2002b and 2003b). Facilities are required to report releases and other waste management activities related to TRI chemicals if they manufacture, process, or otherwise use more than established threshold quantities of these chemicals. Currently for most chemicals, the thresholds are 25,000 pounds for manufacturing and processing and 10,000 pounds for use. Although TRI can provide a general idea of release trends, it is far from exhaustive and should not be used to estimate general public exposure to a chemical (USEPA, 2002b and 2003b). d. *Pesticides in Ground Water Database.* The Pesticides in Ground Water Database (PGWDB) is a compilation of data from ground water studies conducted by Federal, State, and local governments, the pesticide industry, and other institutions between 1971 and 1991 (USEPA, 1992b). Data from 68,824 wells in 45 states are included. The vast majority of the wells (65,865) were drinking water wells. Monitoring was conducted for 258 pesticides and 45 degradates. Not all studies tested for every compound. e. *The National Pesticide Survey.* In 1990, EPA completed a national survey of pesticides in drinking water wells. The purpose of the National Pesticide Survey
(NPS)was to determine the national occurrence frequencies and concentrations of select pesticides in the nation's drinking water wells, and to improve EPA's understanding of how pesticide occurrence in ground water correlates with patterns of pesticide usage and ground water vulnerability. The survey included approximately 1,300 CWS wells and rural domestic wells. Sampling was conducted between 1988 and 1990. Wells were sampled for 101 pesticides, 25 pesticide degradates, and nitrate. The survey targeted areas representing a variety of pesticide usage levels and ground water vulnerability. The survey was designed to provide a statistically reliable estimate of pesticide occurrence in the nation's drinking water wells (USEPA, 1990a). f. *The AWWARF Boron Study.* The American Water Works Research Foundation funded a survey to evaluate the occurrence of boron (as well as hexavalent chromium) in drinking water sources (Frey *et al.* , 2004). The AWWARF study recruited 189 PWSs representing 407 source waters in 41 states. Of the 407 source water sample kits distributed in 2003, approximately 342 were returned. Of these 342 samples, 341 were analyzed for boron. Approximately 67 percent (or 228) represented ground water sources and 33 percent (or 113) represented surface water sources. The results of the AWWARF survey for boron are presented in section IV.B of this action. 3. Supporting Documentation for Occurrence. As mentioned in section II.E, EPA prepared several technical occurrence documents to support this action. These technical occurrence documents include the following: • “The Analysis of Occurrence Data from the Unregulated Contaminant Monitoring
(UCM)Program and National Inorganics and Radionuclides Survey
(NIRS)in Support of Regulatory Determinations for the Second Drinking Water Contaminant Candidate List” (USEPA, 2006c), which this action refers to as the “UCM and NIRS Occurrence Report.” • “The Analysis of Occurrence Data from the First Unregulated Contaminant Monitoring Regulation (UCMR 1) in Support of Regulatory Determinations for the Second Drinking Water Contaminant Candidate List” (USEPA, 2006b), which this action refers to as the “UCMR 1 Occurrence Report.” The “UCM and NIRS Occurrence Report” provides more detailed information about the UCM and the NIRS data, how EPA assessed the data quality, completeness, and representativeness, and how the data were used to generate estimates of contaminant occurrence. The “UCMR 1 Occurrence Report” provides more detailed information about the UCMR 1 data, how EPA assessed the data quality, completeness, representativeness, and how the data were used to generate estimates of contaminant occurrence. The comprehensive regulatory support document (USEPA, 2006a) provides a summary of the results from the drinking water occurrence analyses discussed in the aforementioned technical support documents, as well as information on production and use, environmental releases, and/or occurrence in ambient water, potential health effects, the Agency's preliminary determination, and the rationale for the determination. IV. Preliminary Regulatory Determinations A. Summary of the Preliminary Regulatory Determination The Agency has made a preliminary determination that each of the 11 contaminants listed in Table 3 do not meet all three of the SDWA criteria (discussed in section II.C) and thus do not warrant regulation with an NPDWR. Table 3 also summarizes the primary information used to make these regulatory determinations. Section IV.B of this action provides a more detailed summary of the information and the rationale used by the Agency to reach its preliminary decisions. The Agency solicits public comment on the preliminary determinations for these 11 contaminants. BILLING CODE 6560-50-P EP01MY07.051 BILLING CODE 6560-50-C B. Contaminant Profiles This section provides further details on the background, health, and occurrence information that the Agency used to evaluate each of the 11 candidate contaminants considered for regulatory determination. For each candidate, the Agency evaluated the available human and toxicological data, derived a health reference level, and evaluated the potential and/or likely occurrence and exposed population for the contaminant in public water systems. The Agency used the findings from these evaluations to determine whether the three SDWA statutory requirements were satisfied. As discussed in section II.E, the Agency has also prepared a regulatory support document (USEPA, 2006a) that provides more details on the background, health, and occurrence information/analyses used to evaluate and make preliminary determinations for these 11 candidates. 1. Boron a. *Background.* Boron, a metalloid, tends to occur in nature in the form of borates (e.g., boric acid, borax, boron oxide). Man-made releases are typically in the form of borates or boron halides (e.g., boron trichloride, boron trifluoride). Boron compounds are used in the production of glass, ceramics, soaps, fire retardants, pesticides, cosmetics, photographic materials, and high energy fuels (USGS, 2004; ATSDR, 1992). Natural processes such as the weathering of rocks, volcanic activity, and geothermal steam contribute to the release of boron in the environment. Releases to the environment from human activities occur through the production, use, and disposal of boron-containing compounds (e.g., industrial emissions, fertilizer and herbicide runoff, hazardous waste deposits, and municipal sewage) (HSDB, 2004a; ATSDR, 1992). Although quantitative data are not available on the man-made releases of most borates in the United States, two boron halide compounds, boron trichloride and boron trifluoride, are listed as Toxics Release Inventory
(TRI)chemicals. TRI data for boron trichloride and boron trifluoride are reported for the years 1995 to 2003 (USEPA, 2006d). The TRI data show boron trichloride releases from facilities in 6 States and indicate that air emissions account for all of the total releases of boron trichloride (on- and off-site), which generally fluctuated in the range of hundreds of pounds per year during the period of record. The TRI data show boron trifluoride releases from facilities in 14 States and indicate that air emissions also account for nearly all of the boron trifluoride releases, which ranged in the tens of thousands of pounds annually. b. *Health Effects.* The Institute of Medicine (IOM, 2001) of the National Academies categorizes boron as a possible trace mineral nutrient for humans. Boron is essential for plant growth and deficiency studies in animals and humans have provided some evidence that low intakes of boron affects cellular function and the activity of other nutrients. It may interact with Vitamin D and calcium homeostasis, influence estrogen metabolism, and play a role in cognitive function (IOM, 2001). Iyengar *et al.*
(1988)reported an average dietary intake of 1.5 mg/day for male adults based on the Food and Drug Administration
(FDA)Total Diet Study (TDS). Some human oral data are available from cases where boron was ingested as a medical treatment. When the amount ingested was less than 3.68 mg/kg, subjects were asymptomatic, while doses of 20 and 25 mg/kg resulted in nausea and vomiting. Case reports and surveys of accidental poisonings indicate that the lethal doses of boron range from 15 to 20 grams (approximately 200 to 300 mg/kg) for adults, 5 to 6 grams (approximately 70 to 85 mg/kg) for children, and 2 to 3 grams (approximately 30 to 45 mg/kg) for infants (USEPA, 2004b). The primary adverse effects seen in animals after chronic exposure to low doses of boron generally involve the testes and developing fetus. Chronic effects of dietary boron exposure in two-year studies included testicular atrophy and spermatogenic arrest in dogs, decreased food consumption, suppressed growth, and testicular atrophy in rats, and decreased survival, testicular atrophy, and interstitial cell hyperplasia in mice. Although researchers observed some increases in tumor incidences in the liver and in subcutaneous tissues in mice, based on comparisons to historic controls, these tumors were determined not to be associated with exposure to boron from boric acid (USEPA, 2004b). Boron is not considered mutagenic and the Agency determined that there are inadequate data to assess the human carcinogenic potential for boron (USEPA, 2004c). In developmental studies with rats, mice, and rabbits, oral exposure to boric acid resulted in decreased pregnancy rate, increased prenatal mortality, decreased fetal weights, and increased malformations in fetuses and pups. However, these reproductive effects were associated with maternal toxicity including changes in maternal organ weights, body weights, weight gain, and increased renal tubular dilation and/or regeneration (Price *et al.* , 1990, 1994, 1996; Heindel *et al.* , 1992, 1994; Field *et al.* , 1989). Reproductive effects in males were noted in the subchronic and chronic studies described in the preceding paragraphs. The EPA RfD for boron is 0.2 mg/kg/day (USEPA, 2004c) based on developmental effects in rats from two studies (Price *et al.* , 1996; Heindel *et al.* , 1992). The RfD was derived using the benchmark dose
(BMD)method (bench mark dose level or BMDL from Allen *et al.* , 1996). EPA calculated the HRL of 1.4 mg/L or 1,400 μg/L for boron using the RfD of 0.2 mg/kg-day and a 20 percent screening relative source contribution. EPA also evaluated whether health information is available regarding the potential effects on children and other sensitive populations. Studies in rats, mice, and rabbits identify the developing fetus as potentially sensitive to boron. Price *et al.*
(1996)identified a LOAEL of 13.3 mg/kg-day and an NOAEL of 9.6 mg/kg-day in the developing fetus, based on decreased fetal body weight in rats. Accordingly, boron at concentrations greater than the HRL might have an effect on prenatal development. Individuals with severely impaired kidney function might also be sensitive to boron exposure since the kidney is the most important route for excretion. c. *Occurrence Analyses.* The National Inorganics and Radionuclides Survey
(NIRS)included boron as an analyte. Using data from NIRS, EPA performed an initial evaluation of occurrence and exposure at levels greater than 700 μg/L ( 1/2 the HRL) and greater than 1,400 μg/L (the HRL for boron). The NIRS data indicate that approximately 4.3 percent (or 43) of the 989 ground water PWSs sampled had detections of boron at levels greater than 700 μg/L, affecting approximately 2.9 percent of the population served (or 42,700 people from 1.48 million). Approximately 1.7 percent (or 17) of 989 ground water PWSs sampled had detections of boron at levels greater than 1,400 μg/L, affecting approximately 0.4 percent of the population served (6,400 people from 1.48 million) (USEPA, 2006a and 2006c). Because NIRS did not contain data for surface water systems, the Agency evaluated the results of a survey funded by the American Water Works Association Research Foundation (Frey *et al.* , 2004) to gain a better understanding of the potential occurrence of boron in surface water systems. The AWWARF study recruited 189 PWSs representing 407 source waters that covered 41 states. Of these 407 PWS source water samples, 342 were returned and 341 were analyzed for boron. Of these 341 samples, approximately 67 percent (or 228) represented ground water sources and 33 percent (or 113) represented surface water sources. None of the 113 surface water sources exceeded the boron HRL of 1,400 μg/L and the maximum concentration observed in surface water was 345 μg/L. Extrapolation of the data indicates that 95 percent of the ground water detections had boron levels less than 1,054 μg/L; the maximum observed concentration in ground water was approximately 3,300 μg/L. Seven of the 228 ground water sources (from 5 systems) had boron concentrations greater than 1,400 μg/L (Seidel, 2006). d. *Preliminary Determination.* The Agency has made a preliminary determination not to regulate boron with an NPDWR. While boron was found at levels greater than the HRL (and 1/2 the HRL) in several of the ground water systems surveyed by NIRS, it was not found at levels greater than the HRL (or 1/2 the HRL) in the surface waters sources evaluated in the AWWARF study. Taking this surface water information into account, the Agency believes that the overall national occurrence and exposure from both surface and ground water systems together is likely to be lower than the values observed for the NIRS ground water data. Because boron is not likely to occur at levels of concern when considering both surface and ground waters systems, the Agency believes that a national primary drinking water regulation does not present a meaningful opportunity for health risk reduction. The Agency encourages those States with public water systems that have boron at concentrations above the HRL to evaluate site-specific protective measures and to consider whether State-level guidance (or some other type of action) is appropriate. The Agency also plans to update the Health Advisory for boron to provide more recent health information. The updated Health Advisory will provide information to any States with public water systems that may have boron above the HRL. 2 and 3. Mono- and Di-Acid Degradates of Dimethyl Tetrachloroterephthalate
(DCPA)a. *Background.* Dimethyl tetrachloroterephthalate (DCPA), a synthetic organic compound
(SOC)marketed under the trade name “Dacthal,” is a pre-emergent herbicide historically used to control weeds in ornamental turf and plants, strawberries, seeded and transplanted vegetables, cotton, and field beans. As of 1990, more than 80 percent of its use was for turf, including golf courses and home lawns (USEPA, 1990b). On July 27, 2005, in response to concerns about groundwater contamination (especially for one of the DCPA degradates), the Agency published a **Federal Register** notice announcing that the registrant for Dacthal had voluntarily terminated a number of uses for products containing DCPA (70 FR 43408; USEPA, 2005f). The only uses retained were those for use on sweet potatoes, eggplant, kale and turnips. DCPA is not especially mobile or persistent in the environment. Biodegradation and volatilization are the primary dissipation routes. Degradation of DCPA forms two breakdown products, the mono-acid degradate (or monomethyl tetrachloroterephthalate or MTP) and the di-acid degradate (tetrachloroterephthalic acid or TPA). The di-acid, which is the major degradate, is unusually mobile and persistent in the field, with a potential to leach into water (USEPA, 1998c). Several studies and reports provide estimates of the amount of DCPA used during the 1990s in the United States. The Agency estimated that 1.6 million pounds of DCPA active ingredient a.i. were used annually in the early 1990s (USEPA, 1998c). USGS estimated that approximately 998 thousand pounds of DCPA a.i. were used annually circa 1992 (Thelin and Gianessi, 2000). The National Center for Food and Agricultural Policy (NCFAP, 2004) estimates that approximately 1.7 million pounds of DCPA a.i. were used in 1992 and approximately 600 thousand pounds a.i. were used in 1997 (NCFAP, 2004). The NCFAP data suggest a decrease in the use of DCPA from the early to the late 1990s. b. *Health Effects.* Currently, no subchronic or chronic studies are available to assess the toxicological effects of MTP (the mono-acid degradate) and 3 studies in rats (30 and 90-day feeding studies and a one-generation reproductive study) are available for TPA (the di-acid degradate). The effects of exposure were mild (weight loss and diarrhea) and occurred at doses greater than or equal to 2,000 mg/kg/day. No reproductive effects were observed. The present toxicity database for MTP and TPA is not sufficient to derive RfDs for these two chemicals. However, since the available data indicate that neither MTP nor TPA are more toxic than their parent compound, DCPA, the Agency suggests that the RfD for the DCPA parent would be protective against exposure from these two DCPA metabolites (USEPA, 1998c). Both compounds are formed in the body from the DCPA parent and therefore, the toxicity of these degradates is reflected in the toxicity of the parent. The RfD for DCPA is 0.01 mg/kg/day based on a chronic rat study (ISK Biotech Corporation, 1993) with a NOAEL of 1.0 mg/kg/day and an uncertainty factor of 100 for rat to human extrapolation and intra-species variability. No carcinogenicity studies have been performed using either TPA or MTP. Based on the cancer data for the parent and lack of mutagenicity for TPA and DCPA, the Agency (USEPA, 2004d) concludes that TPA is unlikely to pose a cancer risk. Klopman *et al.*
(1996)evaluated the carcinogenic potential of TPA based on its chemical and biological properties, as well as by a variety of computational tools, and determined that it did not present any substantial carcinogenic risk. There was suggestive evidence that DCPA could be carcinogenic based on an increased incidence of thyroid and liver tumors in rats. The presence of hexachlorobenzene and dioxin as impurities in the material tested could have contributed to the cancer risk. Using the DCPA RfD of 0.01 mg/kg/day (USEPA, 1994) and a 20 percent screening relative source contribution, the Agency calculated an HRL of 0.07 mg/L or 70 μg/L for DCPA and used this HRL for TPA and MTP. EPA also evaluated whether health information is available regarding the potential effects on children and other sensitive populations. There are no data that identify a particular sensitive population for DCPA exposure. Results of a single developmental study indicate that exposure to pregnant dams with doses less than or equal to 2,500 mg/kg/day of TPA via gavage did not have an adverse effect on the fetus. EPA did not identify any data that suggest gender-related differences in toxicity or sensitivity in the elderly. c. *Occurrence.* EPA included the DCPA mono- and di-acid degradates (MTP and TPA) as analytes in the UCMR 1. The analysis results reported for UCMR 1 are the sum of both the mono- and di-acid degradates. EPA converted the analysis result for the degradates to the parent DCPA equivalent and performed an initial evaluation of occurrence and exposure at levels greater than 35 μg/L ( 1/2 the HRL) and greater than 70 μg/L (the HRL). As previously discussed, EPA used the HRL derived for the DCPA parent because it includes the toxicity for the mono- and di-acid degradates. While the UCMR 1 data indicate that the DCPA degradates were the most commonly reported analytes in the monitoring survey (detected at an MRL of 1 μg/L in 772 samples from 175 of the 3,868 PWSs sampled), very few systems exceeded the health level of concern. PWSs with detections were found in 24 States and 1 Territory. The UCMR 1 data indicate that approximately 0.05 percent (or 2) of the 3,868 PWSs sampled had a detection of the DCPA degradates at levels greater than 35 μg/L, affecting approximately 0.33 percent of the population served (or 739,000 people from 225 million). Approximately 0.03 percent (or 1) of the 3,868 PWSs sampled have a detection of the DCPA degradates at levels greater than 70 μg/L, affecting less than 0.01 percent of the population served (or 500 people from 225 million) (USEPA, 2006a and 2006b). EPA also evaluated several sources of supplemental occurrence information for the DCPA parent, the mono-acid degradate and/or the di-acid degradate. These supplemental sources include: • The National Pesticide Survey (NPS), • The provisional pesticide results from the 1992-2001 USGS NAWQA survey of ambient surface and ground waters across the U.S., and • Studies performed by the DCPA or dacthal registrant. As part of the National Pesticide Survey, EPA collected samples from approximately 1,300 community water systems and rural drinking water wells between 1988 and 1990. The NPS included monitoring for the DCPA parent and the di-acid degradate. The DCPA parent was not detected in any wells (using a detection limit of 0.06 μg/L). While the di-acid degradate was detected in 49 of 1,347 wells (using a detection limit of 0.1 μg/L), the maximum reported concentration of 7.2 μg/L did not exceed the HRL of 70 μg/L (USEPA, 1990a). The USGS NAWQA program included the DCPA parent and the mono-acid degradate as analytes in its 1992-2001 monitoring survey of ambient surface and ground waters across the United States. EPA evaluated the results of the provisional data, which are available on the Web (Martin *et al.* , 2003; Kolpin and Martin, 2003). While the USGS detected the DCPA parent in both surface and ground waters, at least 95 percent of the samples from the various land use settings were less than or equal to 0.007 μg/L. The estimated maximum surface water concentration, 40 μg/L (agricultural setting), and the estimated maximum ground water concentration, 10 μg/L (agricultural setting), are both less than 70 μg/L (the DCPA HRL). While the USGS detected the mono-acid degradate in both surface waters and ground waters, at least 95 percent of the samples from the various land use settings were less than 0.07 μg/L (the reporting limit for the mono-acid degradate). The maximum surface water concentration, 0.43 μg/L (agricultural setting), and the maximum ground water concentration, 1.1 μg/L (agricultural setting), are both less than 70 μg/L (the DCPA HRL, which includes the toxicity of the degradates). Beginning in 1992, the registrant for DCPA performed two small-scale ground water occurrence studies in New York and California over a period of 17 and 22 months, respectively. The registrant monitored for the DCPA parent and both of its degradates. The average reported values, which are the sum of the parent and its degradates, were 50.36 μg/L in New York and 12.75 μg/L in California. Neither average value exceeded the HRL of 70 μg/L (USEPA, 1998c). d. *Preliminary Determination.* The Agency has made a preliminary determination not to regulate the DCPA mono-acid degradate and/or the DCPA di-acid degradate with an NPDWR. Because these degradates appear to occur infrequently at health levels of concern in PWSs, the Agency believes that a national primary drinking water regulation does not present a meaningful opportunity for health risk reduction. While the Agency recognizes that these degradates have been detected in the PWSs monitored under the UCMR 1, only 1 PWS had a detect above the HRL. The Agency encourages those States with public water systems that have detects for these degradates to evaluate site-specific protective measures and to consider whether State-level guidance (or some other type of action) is appropriate. The Agency also plans to update the Health Advisory for the DCPA parent to include the mono and di acid degradates, as well as any recent health information related to these compounds. The updated Health Advisory will provide information to any States with public water systems that may have DCPA degradates at levels above the HRL. 4. 1,1-Dichloro-2,2-bis( *p* -chlorophenyl) ethylene
(DDE)a. *Background.* DDE is a primary metabolite of DDT, 15 a pesticide once used to protect crops and eliminate disease-carrying insects in the U.S. until it was banned in 1973. DDE itself has no commercial use and is only found in the environment as a result of contamination and/or breakdown of DDT. While DDE tends to adsorb strongly to surface soil and is fairly insoluble in water, it may enter surface waters from runoff that contains soil particles contaminated with DDE. In both soil and water, DDE is subject to photodegradation, biodegradation, and volatilization (ATSDR, 2002). 15 1,1,1-trichloro-2,2-bis(p-chlorophenyl)ethane. b. *Health Effects.* DDE is not produced as a commercial product. This has limited the numbers of conventional studies that have been performed to assess toxicological properties. Limited data on DDE, mostly from a National Cancer Institute
(NCI)bioassay, suggest that the liver is the primary target organ in mammalian species. However, the NCI study did not evaluate a full array of noncancer endpoints. There is an RfD of 0.0005 mg/kg/day for the parent pesticide DDT based on a NOAEL of 0.05 mg/kg/day from a dietary subchronic study (USEPA, 1996b). In this study, liver lesions were identified at a LOAEL of 0.25 mg/kg/day. Data on DDT identify effects on the nervous and hormonal systems as adverse effects that might also be seen with DDE because it is one of DDT's primary metabolites. The limited data for DDE suggest that any effects on the nervous system are less severe than those seen with DDT. Endocrine effects from DDE are discussed in this section. Based on animal studies DDE is likely to be carcinogenic to humans. This classification is based on increases in the incidence of liver tumors, including carcinomas, in two strains of mice and in hamsters after dietary exposure to DDE. Some epidemiological studies suggest a possible association of the levels of DDE in serum with breast cancer. However, other studies with similar methodologies do not show any association. DDE was mutagenic in mouse lymphoma L5178Y and Chinese hamster V79 cells but negative in the Ames assay. In the 1988 IRIS, EPA calculated an oral slope factor of 0.34 (mg/kg/day) −1 for DDE (USEPA, 1988a). For this regulatory determination, EPA calculated an oral slope factor from the same data set (from the 1988 IRIS) using the EPA 1999 Cancer Guidelines (USEPA, 1999a). The revised slope factor is 1.67 x 10 −1 (mg/kg/day) −1 resulting in a one-in-a-million cancer-risk
(HRL)of 0.2 μg/L. There are some indications that DDE has an adverse impact on the immune system (Banerjee *et al.* , 1996). Oral exposures to 22 mg/kg/day for 6 weeks suppressed serum immunoglobin levels and antibody titers. Inhibition of leucocytes and macrophage migration were observed at the cellular level. Considerable evidence exists that DDE can act as an endocrine disruptor since it binds to the estrogen and androgen receptors. DDE has a stronger affinity for the androgen receptor than for the estrogen receptor. It competes with testicular hormones for the androgen receptor leading to receptor-related changes in gene expression (Kelce *et al.* , 1995). EPA evaluated whether health information is available regarding the potential effects on children and other sensitive populations. Children and adolescents may be sensitive populations for exposure to DDE due to its endocrine disruption properties. Some data suggest that DDE can delay puberty in males (ATSDR, 2002). c. *Occurrence.* EPA included DDE as an analyte in the UCMR 1. Because the HRL for DDE (0.2 μg/L) is lower than the minimum reporting limit
(MRL)used for monitoring (0.8 μg/L), EPA used the MRL value to evaluate occurrence and exposure. The MRL is within the 10 −4 to the 10 −6 cancer risk range for DDE. In evaluating the UCMR 1 data, EPA found that approximately 0.03 percent (or 1) of the 3,867 PWSs sampled had a detection of DDE at the MRL of 0.8 μg/L, affecting approximately 0.01 percent of the population served (or 18,000 people from 226 million) (USEPA, 2006a and 2006b). The USGS NAWQA program included DDE as an analyte in its 1992-2001 monitoring survey of ambient surface and ground waters across the United States. EPA evaluated the results of the provisional data, which are available on the Web (Martin *et al.* , 2003; Kolpin and Martin, 2003), as a supplemental source of occurrence information. While the USGS detected DDE in both surface and ground waters, 95 percent of the samples from the various land use settings were less than 0.006 μg/L (the USGS reporting limit). The maximum surface water concentration, 0.062 μg/L (agricultural setting), and the maximum ground water concentration, 0.008 μg/L (agricultural setting), are both less than 0.2 μg/L (the DDE HRL). d. *Preliminary Determination.* The Agency has made a preliminary determination not to regulate DDE with an NPDWR. Because DDE appears to occur infrequently at levels of concern in PWSs, the Agency believes that a national primary drinking water regulation does not present a meaningful opportunity for health risk reduction. DDE was detected in only one of the PWSs monitored under the UCMR 1 at a level greater than the MRL (0.8 μg/L), a concentration that is within the 10 −4 to the 10 −6 cancer risk range. In addition, ambient water data from the USGS indicate that the maximum concentrations detected in surface and ground water were less than the HRL of 0.2 μg/L. EPA recognizes that DDE is listed as a probable human carcinogen. For this reason, the Agency encourages those States with public water systems that might have DDE above the HRL to evaluate site-specific protective measures and to consider whether State-level guidance (or some other type of action) is appropriate. 5. 1,3-Dichloropropene (1,3-DCP; Telone) a. *Background.* 1,3-Dichloropropene (1,3-DCP), a synthetic volatile organic compound, is used as a pre-plant soil fumigant to control nematodes and other pests in soils to be planted with all types of food and feed crops. 1,3-DCP is typically injected 12″ to 18″ beneath the soil surface and can only be used by certified handlers (USEPA, 1998b). To mitigate risks to drinking water, 1999 labeling requirements restrict the use of 1,3-DCP: • In areas with shallow ground water and vulnerable soils in certain northern tier States (ND, SD, WI, MN, NY, ME, NH, VT, MA, UT, and MT); • In fields within 100 feet of a drinking water well; and • In areas overlying karst 16 geology. 16 Karst is a type of typography that is formed by the dissolution and collapse of soluble rocks (typically limestone and dolomite). According to the Karst Waters Institute, as excerpted by USGS (2006), common geological characteristics of karst regions that influence human use of its land and water resources include ground subsidence, sinkhole collapse, ground water contamination, and unpredictable water supply. Estimates of national annual use during the 1990s vary widely, from approximately 23 to 40 million pounds of active ingredient a.i. Based on information from a 1991 data call-in and other sources, EPA estimates that approximately 23 million pounds of 1,3-DCP a.i. were used annually from 1990 to 1995 (USEPA, 1998b). NCFAP
(2004)estimates that approximately 40 million pounds a.i. were used in 1992 and approximately 35 million pounds a.i. were used in 1997. 1,3-Dichloropropene is listed as a TRI chemical and releases are reported from facilities in 17 States over a time period covering 1988 to 2003 (although not all States had facilities reporting releases every year) (USEPA, 2006e). Air emissions appear to account for most of the on-site (and total) releases and generally declined between 1988 and 2003. A sharp decrease in air emissions is evident between 1995 and 1996. Surface water discharges are minor compared to air emissions and no obvious trend is evident between 1988 and 2003. Reported underground injection, releases to land, and off-site releases are generally insignificant. b. *Health Effects.* Chronic and subchronic exposures to 1,3-DCP at doses of 12.5 mg/kg/day and above in animal dietary studies indicate that 1,3-DCP is toxic to organs involved in metabolism (liver), excretion of conjugated metabolites (e.g., urinary bladder and the kidney) and organs along the portals of entry (e.g., forestomach for oral administration; mucous membrane of the nasal passage and lungs for inhalation exposure). Exposure to 1,3-DCP has not been shown to cause reproductive or developmental effects. Neither reproductive nor developmental toxicity were observed in a two-generation reproductive study in rats or in developmental studies in rats and rabbits at maternal inhalation concentrations up to 376 mg/m 3 (USEPA, 2000a). Even concentrations that produced parental toxicity did not produce reproductive or developmental effects (USEPA, 2000a). An RfD of 0.03 mg/kg/day for 1,3-DCP (USEPA, 2000a) has been established using a benchmark dose
(BMD)analysis based on a two-year chronic bioassay (Stott *et al.* , 1995) in which chronic irritation (forestomach hyperplasia) and significant body weight reduction were the critical and co-critical effects, respectively. A reference concentration
(RfC)of 0.02 mg/m 3 was derived from a two-year bioassay (Lomax *et al.* , 1989), which observed histopathology in the nasal epithelium. Under the proposed cancer risk assessment guidelines, the weight of evidence for evaluation of 1,3-DCP's ability to cause cancer suggest that it is likely to be carcinogenic to humans (USEPA, 2000a). This characterization is supported by tumor observations in chronic animal bioassays for both inhalation and oral routes of exposure. The oral cancer slope factors calculated from chronic dietary, gavage and inhalation data ranged from 5 × 10 − 2 to 1 × 10 − 1 (mg/kg/day) − 1 . Due to uncertainties in the delivered doses in some studies, EPA
(IRIS)recommended using the oral slope factor of 1 × 10 − 1 (mg/kg/day) − 1 from an NTP
(1985)study. Using this oral slope factor, EPA calculated an HRL of 0.4 μg/L at the 10 − 6 cancer risk level. EPA also evaluated whether health information is available regarding the potential effects on children and other sensitive populations. No human or animal studies are available that have examined the effect of 1,3-DCP exposure on juvenile subjects. Therefore, its effects on children are unknown. Developmental studies in rats and rabbits show no evidence of developmental effects and therefore it is unlikely that 1,3-DCP causes developmental toxicity. c. *Occurrence.* EPA included 1,3-DCP as an analyte in the UCM Round 1 and UCM Round 2 surveys. The MRLs for UCM Round 1 ranged from 0.02 to 10 μg/L and the MRLs for UCM Round 2 ranged from 0.08 to 1 μg/L. EPA also analyzed for 1,3-DCP using the samples from the small systems that were included in the UCMR 1 survey. The MRL used for the UCMR 1 survey was 0.5 μg/L. Because some of these reporting limits exceeded the thresholds of interest, the occurrence analyses may result in an underestimate of systems affected (USEPA, 2006a, 2006b and 2006c). However, the MRL values used for UCM Round 1 and UCM Round 2 as well as UCMR 1 are within the 10 − 4 to the 10 − 6 cancer risk range. The UCM Round 1 Cross Section data indicate that approximately 0.16 percent (or 15) of the 9,164 PWSs sampled had detections of 1,3-DCP at levels greater than 0.2 μg/L ( 1/2 the HRL), affecting approximately 0.86 percent of the population served (or 438,000 of 51 million). The UCM Round 1 Cross Section data also indicate the same values when the data are analyzed using 0.4 μg/L (the HRL). That is, 0.16 percent (or 15) of 9,164 PWSs sampled had detections greater than 0.4 μg/L (the HRL), affecting approximately 0.86 percent of the population served (or 438,000 of 51 million people). The 99th percentile of all detections is 2 μg/L and the maximum reported value is 2 μg/L. The UCM Round 2 Cross Section data indicate that approximately 0.30 percent (or 50) of the 16,787 PWSs sampled had detections of 1,3-DCP at levels greater than 0.2 μg/L ( 1/2 the HRL), affecting approximately 0.42 percent of the population served (or 193,000 of 46 million). The UCM Round 2 Cross Section data indicate that approximately 0.23 percent (or 38) of the 16,787 PWSs sampled had detections of 1,3-DCP at levels greater than 0.4 μg/L (the HRL), affecting approximately 0.33 percent of the population served (or 152,000 of 46 million). The 99th percentile of all detections is 39 μg/L and the maximum reported value is 39 μg/L. Because the sample preservative used may have resulted in potential underestimates of occurrence for the UCM Rounds 1 and 2 data, EPA subsequently analyzed for 1,3-DCP using the samples provided by 796 of the small systems included in the recent UCMR 1 survey. None of the 3,719 samples from these 796 small systems (serving a population of 2.8 million) had detects of 1,3-DCP at levels greater than 0.5 μg/L (the minimum reporting limit used for the analysis of 1,3-DCP and a level that is slightly higher than the HRL). EPA also evaluated several sources of supplemental information, which included: • The National Pesticide Survey, • The Pesticides in Ground Water Database, • A well water survey submitted by the registrant of Telone (1,3-DCP), • The USGS VOC National Synthesis Random Source Water Survey, and • The USGS VOC National Synthesis Focused Source Water Survey. As part of the National Pesticide Survey, EPA collected samples from approximately 1,300 community water systems and rural drinking water wells between 1988 and 1990. The NPS included *cis* and *trans* 1,3-DCP as analytes in the monitoring survey. Neither compound was detected in the survey using a minimum reporting limit of 0.010 μg/L (USEPA, 1990a). The Pesticides in Ground Water Database (USEPA, 1992b) indicates that 1,3-DCP was found in 6 of 21,270 ground water wells sampled in 7 States. The 6 wells with positive detections for 1,3-DCP included 3 wells in California (at concentrations ranging from 0.890 to 31.0 μg/L), 2 wells in Florida (at concentrations of 0.279 to 7.83 μg/L), and 1 well in Montana (at concentrations of 18 to 140 μg/L). While most or all of these 6 wells had concentrations greater than the HRL for 1,3-DCP, the overall percentage of positive wells detections was less than 0.1 percent. In 1998, the registrant for Telone (1,3-DCP) submitted a private well water study to the Agency. The well water survey covered 5 regions where Telone was used intensively and evaluated 518 wells (~5,800 samples) for the presence of 1,3-DCP. Of the 518 wells, 65 had detectable levels of 1,3-DCP and/or its metabolites at levels greater than 0.015 μg/L (the detection limit for 1,3-DCP was 0.015 μg/L and the metabolites were 0.023 μg/L). None of the wells exceeded 0.2 μg/L (a level half the EPA-derived HRL for 1,3-DCP) (USEPA, 2004e and 2004f). For the Random Source Water Survey, the USGS collected samples from 954 source waters that supply community water systems between 1999 and 2000. For the Focused Source Water Survey, the USGS collected 451 samples from 134 source waters that supply community water systems between 1999 and 2001. The USGS included 1,3-DCP as an analyte in both surveys. The USGS did not detect 1,3-DCP in any of the source water samples from the Random Source Water Survey using a reporting limit of 0.2 μg/L (a level that is one-half the HRL for 1,3-DCP). In addition, the USGS did not detect 1,3-DCP in any of the source water samples in the Focused Source Water Survey using a detection limit of 0.024 μg/L for cis-1,3-dichloropropene and 0.026 μg/L for trans-1,3-dichloropropene (levels that are about 16 times lower than the HRL for 1,3-DCP) (Ivahnenko *et al.* , 2001; Grady, 2003; Delzer and Ivahnenko, 2003a). d. *Preliminary Determination.* The Agency has made a preliminary determination not to regulate 1,3-DCP with an NPDWR. Because 1,3-DCP appears to occur infrequently at health levels of concern in PWSs, the Agency believes that a national primary drinking water regulation does not present a meaningful opportunity for health risk reduction. While 1,3-DCP was detected in the UCM Round 1 (late 1980s) and the UCM Round 2 (mid 1990s) surveys, it was not detected in a subsequent evaluation of 796 small systems from the UCMR 1 survey. In addition, the USGS did not detect 1,3-DCP in two occurrence studies performed between 1999 and 2001 using monitoring levels that were lower than the HRL. EPA believes the 1999 pesticide labeling requirements, which are intended to mitigate risks to drinking water, may be one reason for the lack of occurrence of 1,3-DCP at levels of concern in subsequent monitoring surveys. EPA recognizes that 1,3-dichloropropene is listed as a probable human carcinogen. For this reason, the Agency encourages those States with public water systems that may have 1,3-dichloropropene above the HRL to evaluate site-specific protective measures and to consider whether State-level (or some other type of action) is appropriate. The Agency also plans to update the Health Advisory document for 1,3-DCP to provide more recent health information. The updated Health Advisory will provide information to any States with public water systems that may have 1,3-DCP above the HRL. 6 and 7. 2,4- and 2,6-Dinitrotoluenes (2,4- and 2,6-DNT) a. *Background.* 2,4- and 2,6-dinitrotoluene (DNT), semi-volatile organic compounds, are two of 6 isomers of dinitrotoluene. Dinitrotoluenes are used in the production of polyurethane foams, automobile air bags, dyes, ammunition, and explosives, including trinitrotoluene or TNT (HSDB, 2004b and 2004c; ATSDR, 1998). Neither 2,4-nor 2,6-DNT occur naturally. They are generally produced as individual isomers or as a mixture called technical grade DNT (tg-DNT). Technical grade DNT primarily contains a mixture of 2,4-DNT and 2,6-DNT with the remainder consisting of the other isomers and minor contaminants such as TNT and mononitrotoluenes (HSDB, 2004b). No recent quantitative estimates of DNT production or use are available. The Hazardous Substances Data Bank (HSDB, 2004b) cites a 1980 EPA Ambient Water Quality Criteria Document that places combined 2,4- and 2,6-DNT production at 272,610,000 pounds in 1975. Both 2,4-DNT and 2,6-DNT are listed as TRI chemicals. TRI data for 2,4-DNT are reported from facilities in 21 States over a time period covering 1988 to 2003. Total releases nationally in 2003 were 14,899 lbs. Releases of all kinds (off-site releases and on-site air, surface, underground injection, and land releases) declined in the early 1990s, and then peaked again around 1999-2001. On-site air emissions and surface water releases of 2,4-DNT were generally the most consistent (least fluctuating) types of releases, with surface water releases generally declining over the period on record (USEPA, 2006f). TRI data for 2,6-DNT are reported from facilities in 10 States over a time period covering 1988 to 2003 (with no more than 9 States having reporting facilities in any one year). Total reported releases for 2003 were 10,937 lbs. Trends for 2,6-DNT are similar to those for 2,4-DNT. The TRI data for 2,6-DNT show a trend of declining releases in the late 1980s and early 1990s, and a subsequent peak around 1999-2001. On-site air emissions and surface water discharges are the most consistent types of release for 2,6-DNT and surface water discharges exhibit a declining trend (USEPA, 2006f). In addition, TRI lists mixed DNT isomer releases as a separate category over the same time period (1990-2003). TRI releases of mixed isomers were reported from facilities in 9 States, with no more than 7 States having reporting facilities in any one year. Total releases in 2003 were 13,790 lbs. Underground injections made up the bulk of on-site releases during the 1990s, but diminished thereafter. Air emissions remained relatively constant. Surface water discharges and releases to land were generally insignificant but peaked in 2003. Off-site releases varied widely. Total releases peaked in 1993 and 1997, and generally diminished in recent years (USEPA, 2006f). b. *Health Effects.* In experimental animal studies, 2,4- and 2,6-DNT appear to be acutely toxic at moderate to high levels (LD <sup>50</sup> 's 17 ranging from 180 to 1,954 mg/kg) when administered orally. In subacute studies (4 weeks) conducted by Lee *et al.* (1978), dogs, rats, and mice were fed 2,4-DNT and studied for toxic effects. A NOAEL of 5 mg/kg/day was established; decreased body weight gain and food consumption, neurotoxic signs, and lesions in the brain, kidneys, and testes occurred at 25 mg/kg/day (the highest dose tested). 17 LD <sup>50</sup> = An estimate of a single dose that is expected to cause the death of 50% of the exposed animals. It is derived from experimental data. Subchronic studies in mice, rats, and dogs that administered 2,4- and 2,6-DNT in the diet produced similar effects in all species. All species exposed to 2,4-DNT exhibited methemoglobinemia, anemia, bile duct hyperplasia sometimes accompanied by hepatic degeneration, and depressed spermatogenesis. Neurotoxicity and renal degeneration occurred in dogs at a dose level of 20 mg/kg/day of 2,6-DNT (Lee *et al.* , 1976). At a dose level of 25 mg/kg/day of 2,4-DNT, male and female dogs developed impaired muscle movement and paralysis, methemoglobinemia, aspermatogenesis, hemosiderosis of the spleen and liver, cloudy swelling of the kidneys, and lesions of the brain (Ellis *et al.* , 1985). These doses were determined to be LOAELs for these studies. 2,4-DNT has been shown to cause reproductive effects in rats, mice, and dogs (Ellis *et al.* , 1979; Lee *et al.* , 1985; Hong *et al.* , 1985; Ellis *et al.* , 1985). Ellis *et al.*
(1979)observed effects in rats following dietary exposure after a dose of 35 mg/kg/day but not 5 mg/kg/day over 3 generations. Male mice fed 2,4-DNT for 13 weeks exhibited testicular degeneration and atrophy and decreased spermatogenesis at 95 mg/kg/day (Hong *et al.* , 1985). In another reproductive study, dogs exhibited mild to severe testicular degeneration and reduced spermatogenesis (Ellis *et al.* , 1985) when administered 2,4-DNT in capsules at 25 mg/kg/day. There are currently no studies of the reproductive or developmental toxicity of 2,6-DNT although a subchronic study in dogs identified atrophy of spermatogenic cells in males suggesting a one- or two-generation study as a data need for 2,6-DNT. Some studies evaluated the effects of DNT in the form of a technical mixture (tg-DNT). In a study by Price *et al.* (1985), the teratogenic potential of tg-DNT (containing approximately 76 percent 2,4-DNT and 19 percent 2,6-DNT) was investigated in rats. The study was conducted in two phases to evaluate the possible teratogenicity of DNT as well as DNT effects on postnatal development. For the first phase, rats were administered 0, 14, 35, 37.5, 75, 100, or 150 mg/kg/day of DNT in corn oil by gavage. In the postnatal phase, rats were administered 14, 35, 37.5, 75, or 100 mg/kg/day of DNT in corn oil by gavage. The NOAEL and LOAEL for developmental toxicity were 14 and 35 mg/kg/day, respectively, based on significant increases in relative liver and spleen weight in the fetuses of dams administered DNT at levels of 35 mg/kg/day or greater. No teratogenic toxicity was seen in the study rats. In chronic exposures, oral dietary administration of 2,4-DNT to dogs primarily affected the nervous system, erythrocytes, and biliary tract (Ellis *et al.* , 1979, 1985). Based on neurotoxicity, hematologic changes, and effects on the bile ducts in dogs, the LOAEL was determined to be 1.5 mg/kg/day and the NOAEL was 0.2 mg/kg/day. EPA established an RfD of 0.002 mg/kg/day for 2,4-DNT (USEPA, 1992c) based on this study. An uncertainty factor of 100, to account for interspecies and intraspecies variability, was applied to derive the RfD. EPA established an RfD of 0.001 mg/kg/day for 2,6-DNT (USEPA, 1992c). This RfD was also based on neurotoxicity, Heinz body formation, biliary tract hyperplasia, liver and kidney histopathology, and death in beagle dogs that were fed gelatin capsules containing 2,6-DNT daily for up to 13 weeks (Lee *et al.* , 1976). The NOAEL for this study was 4 mg/kg/day, and an uncertainty factor of 3,000 (100 for inter- and intra-species variability, 10 for the use of a subchronic study, 3 to account for the limited database) was applied to derive the RfD. DNT is likely to be carcinogenic to humans (classified as a B2 carcinogen; USEPA, 1990c). This is based on significant increases in hepatocellular carcinoma and mammary gland tumors in female rats fed DNT (98 percent 2,4-DNT with 2 percent 2,6-DNT) in the diet in a two-year study (Ellis *et al.* , 1979). The tumor incidence in the female rats was used to establish a slope factor of 6.67 × 10 −1 according to the 1999 EPA guidelines. Concentrations of 5 μg/L, 0.5 μg/L, and 0.05 μg/L are associated with carcinogenic risks of 10 −4 , 10 −5 , and 10 −6 respectively. There were no studies found in the literature that evaluated the effects of 2,4- or 2,6-DNT on children. There is evidence that the pups and fetuses from dams administered tg-DNT had significant increases in relative liver and spleen weights (Price *et al.* , 1985). DNT toxicity may be different in children, compared to adults, since it undergoes bioactivation in the liver and by the intestinal microflora (ATSDR, 1998). Newborns may be more sensitive to DNT-related methemoglobinemia because an enzyme that protects against increased levels of methemoglobin is inactive for a short duration immediately after birth (Gruener 1976; ATSDR, 1998). However, there are no experimental data on differences in children's responses to 2,4-/2,6-DNT. c. *Occurrence.* EPA included both 2,4- and 2,6-DNT as analytes in the UCMR 1. Because the HRL for both 2,4- and 2,6-DNT (0.05 μg/L) is lower than the minimum reporting limit used for monitoring (MRL of 2 μg/L), EPA used the MRL to evaluate occurrence and exposure. The MRL is within the 10 − 4 to the 10 − 6 cancer risk range for either 2,4- or 2,6-DNT. In evaluating the UCMR 1 data, EPA found that 1 of the 3,866 PWSs sampled (or 0.03 percent) detected 2,4-DNT at the MRL of 2 μg/L, affecting 0.02 percent of the population served (or 38,000 people from 226 million). None of the 3,866 PWSs sampled (serving 226 million) detected 2,6-DNT at the MRL of 2 μg/L (USEPA, 2006a and 2006b). EPA also evaluated the results of a USGS review of 3 highway and urban runoff studies (Lopes and Dionne, 1998). These studies showed no detects for either 2,4- or 2,6-DNT using a reporting limit of 5 μg/L (a value within the 10 − 4 to 10 − 6 risk range). d. *Preliminary Determination.* The Agency has made a preliminary determination not to regulate 2,4- or 2,6-DNT with an NPDWR. Because 2,4- and 2,6-DNT appear to occur infrequently at levels of concern in PWSs, the Agency believes that a national primary drinking water regulation does not present a meaningful opportunity for health risk reduction. 2,4-DNT was detected only once at a minimum reporting level that is within the 10 − 4 to the 10 − 6 cancer risk range, while 2,6-DNT was not detected at this same level in any of the PWSs monitored under the UCMR 1. EPA recognizes that 2,4- and 2,6-DNT are listed as probable human carcinogens. For this reason, the Agency encourages those States with public water systems that may have either 2,4- or 2,6-DNT above the HRL to evaluate site-specific protective measures and to consider whether State-level guidance (or some other type of action) is appropriate. The Agency's original Health Advisories for 2,4- and 2,6-DNT were developed for military installations. Because the Agency recognizes that 2,4- and 2,6-DNT may still be found at some military sites, the Agency has updated the Health Advisories to reflect recent health effects publications. The Health Advisories are available for review in the docket. The updated Health Advisories will provide information to any States with public water systems that may have either 2,4- or 2,6-DNT above the HRL. 8. s-Ethyl dipropylthiocarbamate
(EPTC)a. *Background.* EPTC, a synthetic organic compound, is a thiocarbamate herbicide used to control weed growth during the pre-emergence and early post-emergence stages of weed germination. First registered for use in 1958, EPTC is used across the U.S. in the agricultural production of a number of crops, most notably corn, potatoes, dried beans, alfalfa, and snap beans. EPTC is also used residentially on shade trees, annual and perennial ornamentals, and evergreens (USEPA, 1999c). Estimates of EPTC usage in the United States suggest a decline from approximately 17 to 21 million pounds active ingredient in 1987 to approximately 7 to 9 million pounds active ingredient in 1999. TRI data from 1995 to 2003 indicate that most on-site industrial releases of EPTC tend to be releases to air and underground injections. Surface water discharges are minimal in comparison (USEPA, 2006g). Total releases for 2003 were 2,183 lbs. Environmental fate data indicate that EPTC would not be persistent under most environmental conditions. Volatilization into the atmosphere and degradation by soil organisms appear to be the primary dissipation routes. EPTC has a low affinity for binding to the soil so the potential to leach to ground water does exist. If EPTC reaches ground water, volatilization is less likely to occur (USEPA, 1999c). b. *Health Effects.* In acute animal toxicity studies, EPTC was shown to be moderately toxic via oral and dermal routes and highly toxic via inhalation exposures. EPTC is a reversible cholinesterase
(ChE)inhibitor. Similar to other thiocarbamates, it does not produce a consistent ChE inhibition profile. There was no consistent pattern observed in any of the toxicity studies with regard to species, duration of treatment, or the type of ChE enzyme measured. Typically, studies showed inhibition of plasma ChE with dose-related decreases in red blood cell and brain ChE activity. Some studies have shown that brain ChE activity was inhibited without any effect on either plasma or erythrocyte ChE activities. Other studies illustrated erythrocyte ChE inhibition with no effect on either plasma or brain ChE (USEPA, 1999c). In a primary eye irritation study in rabbits, technical grade EPTC was shown to be slightly irritating (USEPA, 1999c). In subchronic and chronic studies performed in both rats and dogs, there was a dose-related increase in the incidence and severity of cardiomyopathy, a disorder of the heart muscle (Mackenzie, 1986; USEPA, 1999c). An increase in the incidence and severity of degenerative effects (neuronal and/or necrotic degeneration) in both the central and peripheral nervous system was observed in rats and dogs following exposure to EPTC (USEPA, 1999c). EPA derived an RfD of 0.025 mg/kg/day for EPTC (USEPA, 1990d; USEPA, 1999c). This value was calculated using a NOAEL of 2.5 mg/kg/day from a study by Mackenzie (1986). An uncertainty factor of 100 was applied for inter- and intraspecies differences. The critical effect associated with the RfD is cardiomyopathy (disease of the heart muscle). In the reregistration of EPTC, the application of a ten-fold Food Quality Protection Act
(FQPA)factor was recommended in order to be protective against residential exposures of infants and children. The Agency derived the HRL for EPTC using the RfD of 0.025 mg/kg/day and a 20 percent relative source contribution. The HRL is calculated to be 0.175 mg/L or 175 μg/L. The Agency used long-term studies in mice and rats and short-term studies of mutagenicity to evaluate the potential for carcinogenicity (USEPA, 1990d). Based on these data and using EPA's 1999 Guidelines for Carcinogen Risk Assessment, EPTC is not likely to be carcinogenic to humans (USEPA, 1999a). EPA also evaluated whether health information is available regarding the potential effects on children and other sensitive populations. Data do not suggest increased pre- or post-natal sensitivity of children and infants to EPTC exposure. In animal studies, adverse developmental effects (i.e., decreased fetal body weight and decreased litter size) were only seen at doses that were toxic to the mother (USEPA, 1999c). Results from both developmental and reproductive studies indicate that there are only minimal adverse effects. The behavior patterns of children that lead to heightened opportunities for exposure in the indoor environment and the need for a developmental neurotoxicity study lead OPP to recommend the application of a ten-fold FQPA factor for EPTC. However, EPA did not apply this factor in the screening analysis because it does not apply to programs other than the pesticide registrations. c. *Occurrence.* EPA included EPTC as an analyte in the UCMR 1. None of the 3,866 PWSs sampled (serving a population of 226 million) had detects of EPTC at the MRL of 1 μg/L. Hence, these data indicate that no occurrence and exposure is expected at levels greater than 87.5 μg/L ( 1/2 the HRL) and greater than 175 μg/L (the HRL) (USEPA, 2006a and 2006b). EPA also evaluated several sources of supplemental information, which included: • The National Pesticide Survey, • The Pesticides in Ground Water Database, and • The provisional pesticide results from the 1992-2001 USGS NAWQA survey of ambient surface and ground waters across the U.S. As part of the National Pesticide Survey, EPA collected samples from approximately 1,300 community water systems and rural drinking water wells between 1988 and 1990. The NPS included EPTC as an analyte in the monitoring survey. EPTC was not detected using a minimum reporting limit of 0.15 μg/L (USEPA, 1990a). The Pesticides in Ground Water Database (USEPA, 1992b) indicates that EPTC was found in 2 of 1,752 ground water wells that were sampled in 10 States. Both contaminated wells were in Minnesota. The detected concentrations ranged from 0.01 to 0.33 μg/L. All of these positive detections are less than the HRL of 175 μg/L, as well as 87.5 μg/L ( 1/2 the HRL). The USGS NAWQA program included EPTC as an analyte in its 1992-2001 monitoring survey of ambient surface and ground waters across the United States. EPA evaluated the results of the provisional data, which are available on the Web (Martin *et al.* , 2003; Kolpin and Martin, 2003). While the USGS detected EPTC in both surface and ground waters, 95 percent of the samples from the various land use settings were less than or equal to 0.018 μg/L. The estimated maximum surface water concentration, 29.6 μg/L (mixed land use settings), and the maximum ground water concentration, 0.45 μg/L (agricultural settings), are both less than 175 μg/L (the EPTC HRL). d. *Preliminary Determination.* The Agency has made a preliminary determination not to regulate EPTC with an NPDWR. Because EPTC does not appear to occur at health levels of concern in PWSs, the Agency believes that a national primary drinking water regulation does not present a meaningful opportunity for health risk reduction. While EPTC has been found in ambient waters, it was detected only at levels less than the HRL (as well as 1/2 the HRL) and it was not found in the UCMR 1 survey of public water supplies. 9. Fonofos a. *Background.* Fonofos, an organophosphate, is a soil insecticide used to control pests such as corn rootworms, cutworms, symphylans (i.e., garden centipedes), and wireworms. Primarily used on corn crops, fonofos was also used on other crops such as asparagus, beans, beets, corn, onions, peppers, tomatoes, cole crops, sweet potatoes, peanuts, peas, peppermint, plantains, sorghum, soybeans, spearmint, strawberries, sugarcane, sugar beets, white (Irish) potatoes, and tobacco (USEPA, 1999d). Fonofos was scheduled for a reregistration decision in 1999. However, before the review was completed, the registrant requested voluntary cancellation. The cancellation was announced in the **Federal Register** on May 6, 1998 (63 FR 25033 (USEPA, 1998d)), with an effective date of November 2, 1998, plus a one-year grace period to permit the exhaustion of existing stocks (USEPA, 1999d). NCFAP data indicate that fonofos use declined significantly during the 1990s (NCFAP, 2004). According to NCFAP, approximately 3.2 million pounds of fonofos a.i. were applied annually around 1992 and approximately 0.4 million pounds a.i. were applied annually around 1997. The U.S. Geological Survey
(USGS)estimates an average of 2.7 million pounds a.i. were used annually around 1992 (Thelin and Gianessi, 2000). Fonofos is moderately persistent in soil and its persistence depends on soil type, organic matter, rainfall, and sunlight. Since fonofos adsorbs moderately well to soil, it is not readily leached or transported to ground water but it can be transported to surface waters in runoff. Fonofos is rapidly degraded by soil microorganisms (Extoxnet, 1993). Fonofos tends to volatilize from wet soil and water surfaces, but the process is slowed by adsorption to organic material in soil, suspended solids, and sediment (HSDB, 2004d). b. *Health Effects.* Fonofos (like many organophosphates) is toxic to humans and animals. Case reports and acute oral toxicity studies in animals indicate that oral exposure to fonofos induces clinical signs of toxicity that are typical of cholinesterase inhibitors. In humans, accidental exposures produced symptoms of acute intoxication, nausea, vomiting, salivation, sweating, muscle twitches, decreased blood pressure and pulse rate, pinpoint pupils, profuse salivary and bronchial secretions, cardiorespiratory arrest, and even death in 1 exposed individual (Hayes, 1982; Pena Gonzalez *et al.* , 1996). In animals, clinical signs of exposure included tremors, salivation, diarrhea, and labored breathing (USEPA, 1996c). Chronic exposure studies also indicated that oral administration of fonofos inhibits cholinesterase (Banerjee *et al.* , 1968; Cockrell *et al.* , 1966; Hodge, 1995; Horner, 1993; Miller, 1987; Miller *et al.* , 1979; Pavkov and Taylor, 1988; Woodard *et al.* , 1969). Cholinesterase inhibition is one of the critical effects associated with the RfD, which was verified by EPA (USEPA, 1991) at 0.002 mg/kg/day. EPA derived the RfD of 0.002 mg/kg/day using a NOAEL of 0.2 mg/kg/day (Hodge, 1995) and a 100-fold uncertainty factor to account for inter- and intraspecies differences. Fonofos is classified as an unlikely human carcinogen (Group E) because there is no evidence of carcinogenic potential in the available long-term feeding studies in rats and mice (Banerjee *et al.* , 1968; Pavkov and Taylor, 1988; Sprague and Zwicker, 1987). In addition, fonofos does not appear to be mutagenic (USEPA, 1996c). EPA evaluated whether health information is available regarding the potential effects on children and other sensitive populations. In the available developmental studies with rabbits (Sauerhoff, 1987) and mice (Minor *et al.* , 1982; Pulsford, 1991), no developmental effects were observed at oral doses as high as 1.5 mg/kg/day in the rabbit (highest dose tested) nor in mice at doses as high as 2.0 mg/kg/day (Minor *et al.* , 1982; Pulsford, 1991). However, in mice, effects were noted at higher dose levels. These effects included an increase in the incidence of variant sternebrae ossifications (at 6 mg/kg/day or greater) and a slight dilation of the fourth brain ventricle in offspring (at 4 mg/kg/day or greater). No developmental neurotoxicity study with fonofos is available for further assessment of this endpoint. In a three-generation reproduction study in rats (Woodard *et al.* , 1968), no treatment-related adverse effects were observed at the 2 dose levels used in this study, 0.5 and 1.58 mg/kg/day. The Agency believes that the current RfD is adequately protective of children. The current fonofos RfD of 0.002 mg/kg/day is 1000-fold lower than the NOAEL observed in the Woodard *et al.*
(1968)developmental studies. Using the RfD of 0.002 mg/kg/day for fonofos and a 20 percent screening relative source contribution, the Agency derived an HRL of 0.014 mg/L and rounded to 0.01 mg/L (or 10 μg/L). c. *Occurrence.* EPA included fonofos as an analyte in the UCMR 1 List 2 Screening Survey. None of the 2,306 samples from the 295 PWSs sampled (serving a population of 41 million) contained detects for fonofos at the MRL of 0.5 μg/L. Hence, these data indicate that no occurrence and exposure is expected at levels greater than 5 μg/L ( 1/2 the HRL) and greater than 10 μg/L (the HRL) (USEPA, 2006a and 2006b). The USGS NAWQA program included fonofos as an analyte in its 1992-2001 monitoring survey of ambient surface and ground waters across the United States. EPA evaluated the results of the provisional data, which are available on the Web (Martin *et al.* , 2003; Kolpin and Martin, 2003). While the USGS detected fonofos in both surface and ground waters, 95 percent of the samples from the various land use settings were less than 0.003 μg/L (the reporting limit). The maximum surface water concentration, 1.20 μg/L (agricultural setting), and the maximum ground water concentration, 0.009 μg/L (agricultural setting), are both less than 10 μg/L and less than 5 μg/L (the fonofos HRL and 1/2 the HRL). d. *Preliminary Determination.* The Agency has made a preliminary determination not to regulate fonofos with an NPDWR. Because fonofos does not appear to occur at health levels of concern in PWSs, the Agency believes that a national primary drinking water regulation does not present a meaningful opportunity for health risk reduction. While fonofos has been found in ambient waters, it was detected only at levels less than the HRL (as well as 1/2 the HRL) and it was not found in UCMR 1 Screening Survey of public water supplies. Fonofos was voluntarily cancelled in 1998 and the Agency expects any remaining stocks and releases into the environment to decline. In addition, since fonofos tends to bind strongly to soil, any releases to the environment are not likely to contaminant source waters. 10. Terbacil a. *Background.* Terbacil, a synthetic organic compound, is a selective herbicide used to control broadleaf weeds and grasses on terrestrial food/feed crops (e.g., apples, mint, peppermint, spearmint, and sugarcane), terrestrial food (e.g., asparagus, blackberry, boysenberry, dewberry, loganberry, peach, raspberry, youngberry, and strawberry), terrestrial feed (e.g., alfalfa, forage, and hay) and forest trees (e.g., cottonwood) (USEPA, 1998e). In 1998, EPA estimated that agricultural usage of terbacil consumed approximately 221,000 to 447,000 pounds of active ingredient annually and non-agricultural usage consumed approximately 9,000 to 14,000 pounds. These estimates are based on data collected mostly between 1990 and 1995, and in some cases as early as 1987 (USEPA, 1998e). According to NCFAP (2004), approximately 298,000 pounds of terbacil a.i. were applied annually in agriculture around 1992 and approximately 342,000 pounds a.i. were applied around 1997. Terbacil is listed as a TRI chemical and data are reported from one or more facilities in a single state, Texas, for the time period covering 1995 to 1997. During this three-year period, all reported releases were on-site releases to surface water that varied between 3,000 to 10,000 pounds annually (USEPA, 2006h). Terbacil is considered a persistent and potentially mobile herbicide in terrestrial environments. Because of its low affinity to soils, it can potentially leach into ground and/or surface waters (USEPA, 1998e; Extoxnet, 1994). b. *Health Effects.* In acute and subchronic toxicity studies, terbacil is practically non-toxic (Haskell Laboratories, 1965a and 1965b). Terbacil does not cause dermal sensitivity in rabbits or guinea pigs and causes mild conjunctival eye irritation in rabbits (Henry, 1986; Hood, 1966). In rats exposed subchronically to dietary terbacil, effects were seen at a LOAEL of 25 mg/kg/day and included increased absolute and relative liver weights, vacuolization, and enlargement of liver cells (Wazeter *et al.* ,1964; Haskell Laboratories, 1965c). A primary target organ in rats following exposure to terbacil is the liver. Chronic effects of dietary terbacil exposure in two-year studies included increases in thyroid-to-body weight ratios, slight increases in liver weights and elevated alkaline phosphatase levels in beagle dogs, significant decreases in body weight in rats, increases in serum cholesterol levels and increases in liver to body weight ratios in rats (Wazeter *et al.* ,1967a; Malek, 1993). In beagle dogs, effects were seen at or above 6.25 mg/kg/day (NOAEL = 1.25 mg/kg/day). In rats, effects ( *i.e.* , decreases in body weight, increases in liver weights and cholesterol levels) were seen at higher levels (LOAELs = 56 mg/kg/day for males and 83 mg/kg/day for females). Terbacil is not considered to be a developmental or reproductive toxicant. In developmental studies, maternal effects were generally seen prior to or at the same levels as developmental effects. Haskell Laboratories
(1980)reported maternal effects ( *i.e.* , decreased body weight) and significant decreases in the number of live fetuses per litter due to early fetal resorption at a LOAEL of 62.5 mg/kg/day in rats. In rabbits administered terbacil via gavage, the maternal and developmental LOAELs were equal (600 mg/kg/day). Maternal toxicity was based on the death of the dams and developmental toxicity was based on a decrease in live fetal weights (Solomon, 1984). No reproductive effects were seen in a three-generation study where terbacil was administered to male and female rats at dose levels of 2.5 and 12.5 mg/kg/day (Wazeter *et al.* , 1967b). Terbacil is not mutagenic. Terbacil was tested and found negative in a chromosomal aberration study in rat bone marrow cells, found negative in a gene mutation assay (with and without S9 activation), and found negative for DNA synthesis when tested up to cytotoxic levels in rats (Cortina, 1984; Haskell Laboratories,1984). Terbacil shows no evidence of carcinogenicity and is unlikely to be carcinogenic to humans (Group E) (USEPA, 1998e). The RfD of 0.013 mg/kg/day for terbacil (USEPA, 1998e) is calculated from a two-year chronic study in beagle dogs. The LOAEL of 6.25 mg/kg/day was based on increased thyroid-to-body weight ratios, slight increases in liver weights, and elevated alkaline phosphatase levels with a NOAEL of 1.25 mg/kg/day. In deriving the RfD, the Agency applied an uncertainty factor of 100 to account for interspecies and intraspecies differences. Using the RfD of 0.013 mg/kg/day and applying a 20 percent screening relative source contribution, the Agency derived an HRL of 0.090 mg/L (or 90 g/L) for terbacil. EPA also evaluated whether health information is available regarding the potential effects on children and other sensitive populations. In the case of terbacil, the Agency determined that there was no need to apply an FQPA factor to the RfD in order to protect children (USEPA, 1998e). Other potentially sensitive subpopulations have not been identified. c. *Occurrence.* EPA included terbacil as an analyte in UCMR 1. None of the 3,866 PWSs sampled (serving a population of 226 million) had detects for terbacil at the MRL of 2 g/L. Hence, these data indicate that no occurrence and exposure is expected at levels greater than 45 g/L ( 1/2 the HRL) and greater than 90 μg/L (the terbacil HRL) (USEPA, 2006a and 2006b). EPA also evaluated several sources of supplemental information, which included: • The National Pesticide Survey, • The Pesticides in Ground Water Database, and • The provisional pesticide results from the 1992-2001 USGS NAWQA survey of ambient surface and ground waters across the U.S. As part of the National Pesticide Survey, EPA collected samples from approximately 1,300 community water systems and rural drinking water wells between 1988 and 1990. The NPS included terbacil as an analyte in the monitoring survey. Terbacil was not detected using a minimum reporting limit of 1.7 μg/L (USEPA, 1990a). The Pesticides in Ground Water Database (USEPA, 1992b) indicates that terbacil was found in 6 of the 288 ground water wells tested for this contaminant in 6 States. Terbacil was found in 1 ground water well in Oregon (at a concentration of 8.9 μg/L) and 5 ground water wells in West Virginia (with concentrations ranging from 0.3 to 1.2 μg/L). All of the positive detections are less than the HRL of 90 μg/L, as well as 45 μg/L ( 1/2 the HRL). The USGS NAWQA program included terbacil as an analyte in its 1992-2001 monitoring survey of ambient surface and ground waters across the United States. EPA evaluated the results of the provisional data, which are available on the Web (Martin *et al.* , 2003; Kolpin and Martin, 2003). While the USGS detected terbacil in both surface and ground waters, 95 percent of the samples from the various land use settings were less than 0.034 μg/L (the USGS reporting limit). The maximum surface water concentration, 0.54 μg/L (agricultural setting), and the maximum ground water concentration, 0.891 μg/L (mixed land use setting), are both less than 90 μg/L and less than 45 μg/L (the terbacil HRL and 1/2 the HRL). d. *Preliminary Determination.* The Agency has made a preliminary determination not to regulate terbacil with an NPDWR. Because terbacil does not appear to occur at health levels of concern in PWSs, the Agency believes that a national primary drinking water regulation does not present a meaningful opportunity for health risk reduction. Terbacil has been found in ambient waters but the levels were less than the HRL (as well as 1/2 the HRL). It was not found in the UCMR 1 survey of public water supplies. 11. 1,1,2,2-Tetrachloroethane a. *Background.* 1,1,2,2-Tetrachloroethane, a volatile organic compound, is not known to occur naturally in the environment (IARC, 1979). Prior to the 1980s, 1,1,2,2-tetrachloroethane was synthesized for use in the production of other chemicals, primarily chlorinated ethylenes. 1,1,2,2-Tetrachloroethane was also once used as a solvent to clean and degrease metals, in paint removers, varnishes, lacquers, and photographic films, and for oil/fat extraction (Hawley, 1981). Commercial production of 1,1,2,2-tetrachloroethane in the U.S. ceased in the 1980s when other processes to generate chlorinated ethylenes were discovered (ATSDR, 1996). Production of 1,1,2,2-tetrachloroethane in the U.S. was approximately 440 million pounds in 1967 (Konietzko, 1984). Production declined to an estimated 34 million pounds by 1974 (ATSDR, 1996). Although U.S. commercial production ceased in the 1980s, 1,1,2,2-tetrachloroethane is still generated as a byproduct and/or intermediate in the production of other chemicals. TRI data indicate that environmental releases have generally declined from a high of about 175,000 pounds in 1988 to a low of 3,500 pounds in 2003. Most releases took the form of air emissions, though surface water discharges were also documented nearly every year (USEPA, 2006i). Volatilization from water or soil surfaces to the atmosphere appears to be the primary dissipation route for 1,1,2,2-tetrachloroethane. In subsurface soils and ground water, 1,1,2,2-tetrachloroethane is subject to biodegradation by soil organisms and/or chemical hydrolysis by water (ATSDR, 1996). b. *Health Effects.* Data on the toxicity of 1,1,2,2-tetrachloroethane in humans are limited, consisting of one experimental inhalation study, a few case reports of suicidal or accidental ingestion, and dated occupational studies. In most cases, there was no quantification of the exposure. Respiratory and mucosal effects, eye irritation, nausea, vomiting, and dizziness were reported by human volunteers exposed to 1,1,2,2-tetrachloroethane vapors under controlled chamber conditions (Lehmann and Schmidt-Kehl, 1936). Effects from non-lethal occupational exposures included gastric distress (i.e., pain, nausea, vomiting), headache, loss of appetite, an enlarged liver, and cirrhosis (Jeney *et al.* , 1957; Lobo-Mendonca, 1963; Minot and Smith, 1921). There have been a variety of animal studies in rats and mice using both the inhalation and oral exposure routes. Recent studies by the National Toxicology Program (NTP, 2004) provide a detailed evaluation of the short-term and subchronic oral toxicity of 1,1,2,2-tetrachloroethane and confirm many of the observations from earlier studies. In rats and mice exposed orally, the liver appears to be the primary target organ. The RfD (10 μg/kg/day) for 1,1,2,2-tetrachloroethane was derived from the BMDL for a 1 standard deviation change in relative liver weight, a biomarker for liver toxicity. A 1,000-fold uncertainty factor was applied in the RfD determination. A National Cancer Institute
(1978)bioassay of 1,1,2,2-tetrachloroethane found clear evidence of carcinogenicity in male and female B6C3F1 mice based on a dose-related statistically significant increase in liver tumors. There was equivocal evidence for carcinogenicity in Osborn Mendel rats because of the occurrence of a small number of rare-for-the species neoplastic and preneoplastic lesions in the livers of the high dose animals. The Agency used the slope factor of 8.5 x 10 −2 for the tumors in female mice to derive the HRL of 0.4 μg/L for use in the analysis of the occurrence data for 1,1,2,2-tetrachloroethane. Information on the reproductive effects of 1,1,2,2-tetrachloroethane is limited. There is a single one-generation inhalation study that does not follow a standard methodology and examined a small number of rats (5 females and 7 males) exposed via inhalation to 1 dose (13.3 mg/m 3 ). There were no statistically significant differences in the percentage of females having offspring, number of pups per litter, average birth weight, sex ratio, or post natal offspring mortality (Schmidt *et al.* , 1972). Effects on sperm in male rats were seen after oral (27 mg/kg/day; NTP, 2004) and inhalation (13 mg/m 3 ; Schmidt *et al.* , 1972) exposures. Similar effects were seen in mice but at higher doses. Fetal toxicity did not occur in the absence of maternal toxicity. Developmental range-finding studies conducted for NTP (1991a and b) found that 1,1,2,2-tetrachloroethane was toxic to the dams and pups of Sprague Dawley rats and CD-1 Swiss mice. Rats were more sensitive than mice. The NOAEL in the rats for both maternal toxicity and associated fetal toxicity was 34 mg/kg/day with a LOAEL of 98 mg/kg/day. In mice, the NOAEL was 987 mg/kg/day and the LOAEL was 2,120 mg/kg/day. EPA also evaluated whether health information is available regarding the potential effects on children and other sensitive populations. Individuals with preexisting liver and kidney damage would likely be sensitive to 1,1,2,2-tetrachloroethane exposure. Low intake of antioxidant nutrients (e.g., Vitamin E, Vitamin C, and selenium) could be a predisposing factor for liver damage. In addition, individuals with a genetically low capacity to metabolize dichloroacetic acid (the primary metabolite of 1,1,2,2-tetrachloroethane) may be at greater risk than the general population as a result of 1,1,2,2-tetrachloroethane exposure. c. *Occurrence.* EPA included 1,1,2,2-tetrachloroethane as an analyte in the UCM Round 1 and UCM Round 2 surveys. EPA evaluated the UCM Round 1 Cross Section and the UCM Round 2 Cross Section data at levels greater than 0.2 μg/L ( 1/2 the HRL) and greater than 0.4 μg/L (the HRL) (USEPA, 2006a and 2006c). The MRLs for UCM Round 1 ranged from 0.1 to 10 μg/L and the MRLs for UCM Round 2 ranged from 0.1 to 2.5 μg/L. Because some of the reporting limits exceeded the thresholds of interest, the occurrence analyses may result in an underestimate of systems affected. However, all the MRL values used for UCM Round 1 and UCM Round 2 are within the 10 −4 to the 10 −6 cancer risk range. Analysis of UCM Round 1 Cross Section data indicates that approximately 0.22 percent (or 44) of the 20,407 PWSs sampled had detections of 1,1,2,2-tetrachloroethane at levels greater than 0.20 μg/L ( 1/2 the HRL), affecting approximately 1.69 percent of the population served (or 1.6 million of 95 million). The UCM Round 1 Cross Section data indicate that approximately 0.20 percent (or 41) of the 20,407 PWSs sampled had detections of 1,1,2,2-tetrachloroethane at levels greater than 0.4 μg/L (the HRL), affecting approximately 1.63 percent of the population served (or 1.5 million of 95 million). The 99th percentile of all detects is 112 μg/L and the maximum reported value is 200 μg/L. Analysis of the UCM Round 2 Cross Section data indicate that approximately 0.07 percent (or 18) of the 24,800 PWSs sampled had detections of 1,1,2,2-tetrachloroethane at levels greater than 0.2 μg/L ( 1/2 the HRL), affecting approximately 0.51 percent of the population served (or 362,000 of 71 million). The UCM Round 2 Cross Section data indicate that approximately the same percentage and number of the PWSs sampled (0.07 percent or 17 of the 24,800) had detections of 1,1,2,2-tetrachloroethane at levels greater than 0.4 μg/L (the HRL), affecting approximately 0.08 percent of the population served (or 56,000 of 71 million). The 99th percentile of all detects is 2 μg/L and the maximum reported value is 2 μg/L. EPA also evaluated several sources of supplemental information, which included the USGS VOC National Synthesis Random Source Water Survey and the Focused Source Water Survey. For the Random Source Water Survey, the USGS collected samples from 954 source waters that supply community water systems between 1999 and 2000. For the Focused Source Water Survey, the USGS collected 451 samples from 134 source waters that supply community water systems between 1999 and 2001. The USGS included 1,1,2,2-tetrachloroethane as an analyte in both surveys and did not detect it in any of the source water samples using a reporting limit of 0.2 μg/L (a level that is less than the 1,1,2,2-tetrachloroethane HRL). In addition, USGS did not detect 1,1,2,2-tetrachloroethane when using a detection level of 0.026 μg/L (a level that is over 10 times lower than the 1,1,2,2-tetrachloroethane HRL) in the focused survey (Ivahnenko *et al.* , 2001, Grady, 2003, Delzer and Ivahnenko, 2003a). d. *Preliminary Determination.* The Agency has made a preliminary determination not to regulate 1,1,2,2-tetrachloroethane with an NPDWR. Because 1,1,2,2-tetrachloroethane appears to occur infrequently at health levels of concern in PWSs, the Agency believes that a national primary drinking water regulation does not present a meaningful opportunity for health risk reduction. While 1,1,2,2-tetrachloroethane was detected in both the UCM Round 1 and the UCM Round 2 surveys, the percentage of detections had decreased by the time the UCM Round 2 survey was performed in the mid-1990's. In addition, the USGS did not detect 1,1,2,2-tetrachloroethane in two subsequent monitoring surveys of source waters that supply community water systems using a reporting limit that is less than the 1,1,2,2-tetrachloroethane HRL. The Agency believes that this decrease in detections occurred because commercial production of 1,1,2,2-tetrachloroethane ceased in the mid-1980's. Hence, the Agency does not expect 1,1,2,2-tetrachloroethane to occur in many public water systems today. EPA recognizes that 1,1,2,2-tetrachloroethane is listed as a likely human carcinogen. For this reason, the Agency encourages those States with public water systems that may have 1,1,2,2-tetrachloroethane above the HRL to evaluate site-specific protective measures and to consider whether State-level guidance (or some other type of action) is appropriate. The Agency also plans to update the Health Advisory document for 1,1,2,2-tetrachloroethane to provide more recent health information. The updated Health Advisory will provide information to any States with public water systems that may have 1,1,2,2-tetrachloroethane at levels above the HRL. V. What Is the Status of the Agency's Evaluation of Perchlorate? At this time, the Agency is not making a preliminary determination as to whether a national primary drinking water regulation is needed for perchlorate. However, the Agency has placed a high priority on making a regulatory determination for perchlorate and will publish a preliminary determination as soon as possible. EPA is not able to make a preliminary determination at this time because, in order to evaluate perchlorate against the three SDWA statutory criteria, the Agency believes additional information may be needed to more fully characterize perchlorate exposure and determine whether regulating perchlorate in drinking water presents a meaningful opportunity for health risk reduction. This is particularly true if the Agency uses food exposure data to first calculate a relative source contribution
(RSC)and corresponding health reference level
(HRL)below the drinking water equivalent level
(DWEL)18 in order to determine whether regulating perchlorate would present a meaningful opportunity for health risk reduction. However, the Agency is considering several other approaches, discussed below, for making this statutory determination and is requesting public comment on the strengths and limitations of these approaches. 18 DWEL = [(Reference Dose × Body Weight of 70 kg) / Drinking Water Intake of 2 L per day]. The following sections explain why EPA is not making a preliminary regulatory determination for perchlorate at this time, and discusses the information the Agency has collected to date (that may be relevant to making a preliminary regulatory determination), the additional information the Agency is soliciting in this action, and options for additional analyses that the Agency may conduct to support a regulatory determination. Sections V.A through V.D provide a summary of the available and relevant information/data that the Agency has collected and reviewed regarding the sources of perchlorate in the environment, its potential health effects, and its occurrence in drinking water, food, human urine, breast milk, and amniotic fluid. Section V.E explains the Agency's basis for not making a preliminary regulatory determination for perchlorate at this time and Section V.F. presents the options the Agency is considering to better characterize perchlorate exposure and the alternate approaches that EPA is considering for making a preliminary regulatory determination. This action provides an opportunity for the public to submit other relevant data that may further characterize exposure to perchlorate through the consumption of foods and/or through other pathways and to comment on these alternate approaches. The Agency in particular seeks comment on the use of urine biomonitoring data in estimating perchlorate exposure. The Agency will consider any relevant information/data provided in response to this action as the Agency determines whether to regulate perchlorate with a national primary drinking water regulation and how best to proceed to address perchlorate. A. Sources of Perchlorate Perchlorate (ClO <sup>4</sup> - ) is an anion commonly associated with the solid salts of ammonium, magnesium, potassium, and sodium perchlorate. Perchlorate salts are highly soluble in water, and because perchlorate sorbs poorly to mineral surfaces and organic material, perchlorate can be mobile in surface and subsurface aqueous environments. Although commonly known as a man-made chemical, perchlorate also may be derived from natural processes. While perchlorate has a wide variety of industrial uses, it is primarily used in the form of ammonium perchlorate as an oxidizer in solid fuels used to power rockets, missiles, and fireworks. Approximately 90 percent of perchlorate is manufactured for this application (Wang *et al.* , 2002). Perchlorate can also be present as an ingredient or as an impurity in road flares, lubricating oils, matches, aluminum refining, rubber manufacturing, paint and enamel manufacturing, leather tanning, paper and pulp processing (as an ingredient in bleaching powder), and as a dye mordant. Perchlorate can also occur naturally in the environment. Chile possesses caliche ores rich in sodium nitrate (NaNO <sup>3</sup> ), which are also a natural source of perchlorate (Schilt, 1979 and Ericksen, 1983). These Chilean nitrate salts (saltpeter) have been mined and refined to produce commercial fertilizers, which before 2001 accounted for about 0.14 percent of U.S. fertilizer application (USEPA, 2001d). The USEPA (2001d) conducted a broad survey of fertilizers and other raw materials and found that all products surveyed were devoid of perchlorate except for those known to contain or to be derived from mined Chilean saltpeter. Perchlorate has also been found in other geologic materials. Orris *et al.*
(2003)measured perchlorate at levels exceeding 1,000 parts per million (ppm or mg/kg) in several samples of natural minerals, including potash ore from New Mexico and Saskatchewan (Canada), playa crust from Bolivia, and hanksite from California. Texas Tech University Water Resources Center conducted a large-scale sampling program to determine the source and distribution of perchlorate in northwest Texas groundwater (Jackson *et al.* , 2004; Rajagopalan *et al.* , 2006). Perchlorate was detected at concentrations greater than 0.5 g/L in 46 percent of public wells and 47 percent of private wells. Jackson *et al.*
(2004)hypothesized that atmospheric production and/or surface oxidative weathering is the source of the perchlorate. In related research, Dasgupta *et al.*
(2005)detected perchlorate in many rain and snow samples and demonstrated that perchlorate is formed by a variety of simulated atmospheric processes suggesting that natural, atmospherically- derived perchlorate exists in the environment. Barron *et al.*
(2006)developed a method for the rapid determination of perchlorate in rainwater samples, with a detection limit between 70 and 80 ng/L. Of the ten rainwater samples collected in Ireland in 2005, perchlorate was detected in 4 samples at concentrations between 0.075 and 0.113 g/L, and in 1 other sample at 2.8 g/L. Kang *et al.*
(2006)conducted seven-day experiments to determine if it was possible to produce perchlorate by exposing various chlorine intermediates to UV radiation in the form of high intensity UV lamps and/or ambient solar radiation. Perchlorate formation was demonstrated in aqueous salt solutions with initial concentrations of hypochlorite, chlorite, or chlorate between 100 and 10,000 mg/L. After a limited investigation, the Massachusetts Department of Environmental Quality (MA DEP, 2005) found that perchlorate may be present in sodium hypochlorite solutions used in water and wastewater treatment plants, and that the level of occurrence depends upon storage conditions and the initial purity of the stock solution (MA DEP, 2005). According to MA DEP (2005), the Town of Tewksbury conducted a small study to evaluate the impact of storage conditions (temperature and light) on a new shipment of sodium hypochlorite stock solution. Tewksbury found that the perchlorate concentration in the new stock solution increased from 0.2 g/L to levels ranging from 995 to 6,750 g/L depending on the storage conditions. Accounting for the large dilution factor ( *e.g.* , 20,000 to 1 ratio) used in chlorination processes at drinking water treatment plants, MA DEP
(2005)concluded that “absent additional efforts to minimize breakdown of hypochlorite solutions, it would appear that low levels of the perchlorate ion (0.2 to 0.4 g/L) detected in a drinking water supply disinfected with sodium hypochlorite solutions could be attributable to the chlorination process.” It is not clear at this time what proportion of perchlorate found in public water supplies or entering the food chain comes from these various anthropogenic and natural sources. The significance of different sources probably varies regionally. A study by Dasgupta *et al.*
(2006)analyzes the three principal sources of perchlorate and their relative contributions to the food chain. These are its use as an oxidizer including rocket propellants, Chilean nitrate used principally as fertilizer, and that produced by natural atmospheric processes. B. Health Effects Perchlorate can interfere with the normal functioning of the thyroid gland by competitively inhibiting the transport of iodide into the thyroid. Iodide is an important component of two thyroid hormones, T4 and T3, and the transfer of iodide from the blood into the thyroid is an essential step in the synthesis of these two hormones. Iodide transport into the thyroid is mediated by a protein molecule known as the sodium (Na+)—iodide (I-) symporter (NIS). NIS molecules bind iodide with very high affinity, but they also bind other ions that have a similar shape and electric charge, such as perchlorate. The binding of these other ions to the NIS inhibits iodide transport into the thyroid, which can result in intrathyroidal iodide deficiency and consequently decreased synthesis of T4 and T3. There is compensation for iodide deficiency, however, such that the body maintains the serum concentrations of thyroid hormones within narrow limits through feedback control mechanisms. This feedback includes increased secretion of thyroid stimulating hormone
(TSH)from the pituitary gland, which has among its effects the increased production of T4 and T3 (USEPA, 2005e). Sustained changes in thyroid hormone and TSH secretion can result in thyroid hypertrophy and hyperplasia (abnormal growth or enlargement of the thyroid) (USEPA, 2005e). In January 2005, the National Research Council
(NRC)of the National Academies of Science
(NAS)published “Health Implications of Perchlorate Ingestion,” a review of the current state of the science regarding potential adverse health effects of perchlorate exposure and mode-of-action for perchlorate toxicity (NRC, 2005). Based on recommendations of the NRC, EPA chose data from the Greer *et al.*
(2002)human clinical study as the basis for deriving a reference dose
(RfD)for perchlorate (USEPA, 2005e). Greer *et al.*
(2002)report the results of a well-controlled study that measured thyroid iodide uptake, hormone levels, and urinary iodide excretion in a group of 24 healthy adults administered perchlorate doses orally over a period of 14 days. Dose levels ranged from 0.007 to 0.5 mg/kg/day in the different experimental groups. No significant differences were seen in measured serum thyroid hormone levels (T3, T4, total and free) in any dose group. The statistical no observed effect level
(NOEL)for perchlorate-induced inhibition of thyroid iodide uptake was 0.007 mg/kg/day. Although the NRC committee concluded that hypothyroidism is the first adverse effect in the continuum of effects of perchlorate exposure, NRC recommended that “the most health-protective and scientifically valid approach” was to base the perchlorate RfD on the inhibition of iodide uptake by the thyroid (NRC, 2005). NRC concluded that iodide uptake inhibition, although not adverse, is the key biochemical event in the continuum of possible effects of perchlorate exposure and would precede any adverse health effects of perchlorate exposure. The lowest dose (0.007 mg/kg/day) administered in the Greer *et al.*
(2002)study was considered a NOEL (rather than a NOAEL) because iodide uptake inhibition is not an adverse effect but a biochemical change (USEPA, 2005e). A summary of the data considered and the NRC deliberations can be found in the NRC report
(2005)and the EPA Integrated Risk Information System
(IRIS)summary (USEPA, 2005e). The NRC recommended that EPA apply an intraspecies uncertainty factor of 10 to the NOEL to account for differences in sensitivity between the healthy adults in the Greer *et al.*
(2002)study and the most sensitive population, fetuses of pregnant women who might have hypothyroidism or iodide deficiency. Because the fetus depends on an adequate supply of maternal thyroid hormone for its central nervous system development during the first trimester of pregnancy, iodide uptake inhibition from low-level perchlorate exposure has been identified as a concern in connection with increasing the risk of neurodevelopmental impairment in fetuses of high-risk mothers (NRC, 2005). The NRC
(2005)viewed the uncertainty factor of 10 as conservative and health protective given that the point of departure is based on a non-adverse effect (iodide uptake inhibition) that precedes the adverse effect in a continuum of possible effects of perchlorate exposure. NRC concluded that no uncertainty factor was needed for the use of a less-than chronic study, for deficiencies in the database, or for interspecies variability. To protect the most sensitive human population from chronic perchlorate exposure, EPA derived an RfD of 0.0007 mg/kg/day with a ten-fold total uncertainty factor from the NOEL of 0.007 mg/kg/day (USEPA, 2005e). Blount *et al.* (2006b) recently published a study examining the relationship between urinary levels of perchlorate and serum levels of TSH and total T4 in 2,299 men and women (ages 12 years and older), who participated in CDC's 2001-2002 National Health and Nutrition Examination Survey (NHANES). 19 Blount *et al.* (2006b) evaluated perchlorate along with covariates known or likely to be associated with T4 or TSH levels to assess the relationship between perchlorate and these hormones, and the influence of other factors on this relationship. These covariates included sex, age, race/ethnicity, body mass index, serum albumin, serum cotinine (a marker of tobacco smoke exposure), estimated total caloric intake, pregnancy status, post-menopausal status, premenarche status, serum C-reactive protein, hours fasting before sample collection, urinary thiocyanate, urinary nitrate, and use of selected medications. The study found that perchlorate was a significant predictor of thyroid hormones in women, but not men. After finding evidence of gender differences, the researchers focused on further analyzing the NHANES data for the 1,111 women participants. They divided these 1,111 women into two categories, higher-iodide and lower-iodide, using a cut point of 100 μg/L of urinary iodide based on the World Health Organization
(WHO)definition of sufficient iodide intake. 20 Hypothyroid women were excluded from the analysis. According to the study authors, about 36 percent of women living in the United States have urinary iodide levels less than 100 μg/L (Caldwell *et al.* , 2005). For women with urinary iodide levels less than 100 μg/L, the study found that urinary perchlorate is associated with a decrease in (a negative predictor for) T4 levels and an increase in (a positive predictor for) TSH levels. For women with urinary iodide levels greater than or equal to 100 μg/L, the researchers found that perchlorate is a significant positive predictor of TSH but not a predictor of T4. The study found that perchlorate was not a significant predictor of T4 or TSH in men. The researchers state that perchlorate could be a surrogate for another unrecognized determinant of thyroid function. Also, the study reports that while large doses of perchlorate are known to decrease thyroid function, this is the first time an association of decreased thyroid function has been observed at these low levels of perchlorate exposure. Of note is that the vast majority of the participants in this group had urinary levels of perchlorate corresponding to estimated dose levels that are below the RfD of 0.0007 mg/kg/day. The clinical significance of the variations in T4/TSH levels, which were generally within normal limits, has not been determined. The researchers noted several limitations of the study (e.g., assumption that urinary perchlorate correlates with perchlorate levels in the stroma and tissue and preference for measurement of free T4 as opposed to total T4) and recommended that these findings be confirmed in at least one more large study focusing on women with low urine iodide levels. It is also not known whether the association between perchlorate and thyroid hormone levels is causal or mediated by some other correlate of both, although the relationship between urine perchlorate and total TSH and T4 levels persisted after statistical adjustments for some additional covariates known to predict thyroid hormone levels (e.g., total kilocalorie intake, estrogen use, and serum C-reactive protein levels). A planned follow-up study will include additional measures of thyroid health and function (e.g., TPO-antibodies, free T4). As EPA proceeds towards a regulatory determination for perchlorate, the Agency will continue to review any new findings/studies on perchlorate and their relationship to thyroid function as they become available. 19 While CDC researchers measured urinary perchlorate concentration for 2,820 NHANES participants, TSH and total T4 serum levels were only available for 2,299 of these participants. 20 WHO notes that the prevalence of goiter begins to increase in populations with a median iodide intake level below 100 μg/L (WHO, 1994). C. Occurrence in Water, Food, and Humans 1. Sources of Perchlorate. Section V.A. summarizes the potential sources of perchlorate in the environment. 2. Studies on Perchlorate Occurrence in Public Drinking Water Systems and/or Drinking Water Sources. EPA included perchlorate as an analyte in the 1999 Unregulated Contaminant Monitoring Regulation (UCMR 1) and collected drinking water occurrence data for perchlorate from 3,858 public water systems
(PWSs)between 2001 and 2005. EPA analyzed the available UCMR 1 data on perchlorate at concentrations greater than or equal to 4 μg/L, the minimum reporting limit
(MRL)for EPA Method 314.0. 21 The Agency found that approximately 4.1 percent (or 160) of 3,858 PWSs that sampled and reported under UCMR 1 had at least 1 analytical detection of perchlorate (in at least 1 entry/sampling point) at levels greater than or equal to 4 μg/L. These 160 systems are located in 26 states and 2 territories. Of these 160 PWSs, 8 are small systems (serving 10,000 or fewer people) and 152 are large systems (serving more than 10,000 people). Approximately 1.9 percent (or 637) of the 34,193 samples collected (by these 3,858 PWSs) had positive detections of perchlorate at levels greater than or equal to 4 μg/L. The maximum reported concentration of perchlorate was 420 μg/L, which was found in a surface water sample from a PWS in Puerto Rico. The average concentration of perchlorate for those samples with positive detections for perchlorate was 9.85 μg/L and the median concentration was 6.40 μg/L. 21 EPA Method 314.0 was the analytical method approved and used for UCMR 1 at the time of data collection. These 160 PWSs (with at least 1 analytical detection for perchlorate at levels greater than or equal to 4 μg/L) serve approximately 7.5 percent (or 16.8 million) of the 225 million people served by the 3,858 PWSs that sampled and reported results under UCMR 1. The 16.8 million population-served value represents the total number of people served by the 160 PWSs with at least one detect. Not all people served by these systems necessarily have perchlorate in their drinking water. Some of these 160 public water systems have multiple entry points to the distribution system and not all of the entry points sampled had positive detections for perchlorate in the UCMR 1 survey. An alternative approach to the system-level assessment of populations served is to use an assessment at the entry (sampling) point level. 22 EPA does not have population-served values for each entry point at the system level. However, an assessment can be performed by assuming that each entry (or sampling) point at a public water system serves an equal proportion of the total population-served by the system. In other words, for the alternative assessment, the population served by each system is assumed to be equally distributed across all entry (or sampling) points at each system. For example, if a system serves a million people and has 5 entry points, it is assumed that each entry point serves 200,000 people. Using this approach and counting only the population served for the entry points with positive detections (concentrations greater than or equal to 4 μg/L), the total population served by these entry points with perchlorate detections is approximately 5 million. Section V.E provides the number of systems and population-served estimates for other thresholds of interest. 22 EPA acknowledges that uncertainties exist in the population-served estimates for this alternative assessment since the population for a system is assumed to be equally distributed across the entry points for that system. Because the actual population-served by an entry point is not known, this alternative approach has an equal chance of underestimating or overestimating the actual population-served by entry points with positive detections for perchlorate. In addition, this approach could underestimate the population served that is potentially exposed to perchlorate and overestimate the level of exposure because it can not incorporate the effects of mixing of water between different entry points within the distribution system. This is because the approach cannot account for the dilution that may occur when water that has no detections of perchlorate is mixed within the distribution system with water that has positive detections for perchlorate. The California Department of Health Services (CA DHS) began monitoring for perchlorate in 1997. In 1999, CA DHS began requiring monitoring for perchlorate for drinking water sources that were identified as vulnerable to perchlorate contamination under California's own State monitoring program (i.e., Unregulated Chemicals for which Monitoring is Required). About 60 percent (or 7,100) of all drinking water sources in California (about 12,000) were monitored for perchlorate under the State monitoring program. Between June 2001 and June 2006, CA DHS
(2006)reports that 284 (about 4%) of the approximately 7,100 water sources that monitored had at least 2 or more positive detections for perchlorate at concentrations greater than or equal to 4 μg/L (the reporting limit). These 284 sources supply water for 77 drinking water systems (CA DHS, 2006) and represent active and standby sources (and exclude inactive, destroyed, and abandoned sources, and monitoring and agricultural wells) (CA DHS, 2006). In 2005, the State of Massachusetts's Department of Environment Protection (MA DEP) reported monitoring results for 85 percent (379 of 450) of its community water systems and 86 percent (212 of 250) of its non-transient, non-community water systems. MA DEP found that 9 (1.5%) of the 591 public water systems detected perchlorate at levels greater than or equal to 1 μg/L (the reporting limit used for a modified version of EPA Method 314.0). MA DEP found that the occurrence of perchlorate for these water systems could be traced to the use of blasting agents, military munitions, fireworks, and, to a lesser degree, sodium hypochlorite disinfectant (MA DEP, 2005). 3. Studies on Perchlorate Occurrence in Foods, Plants, Beverages, and Dietary Supplements. The Food and Drug Administration (FDA), the United States Department of Agriculture (USDA), and researchers from academia and industry have studied perchlorate in foods. Some of these studies are described briefly in this section, and also summarized in Table 4. EPA has concluded that the sampling results described in this section and Table 4 are too limited to characterize food-borne exposure to perchlorate on a national scale. The sampling data are limited in the types of foods sampled, sample sizes, geographic coverage, and/or analytical method adequacy and many were targeted to foods or areas known or likely to have elevated levels of perchlorate. Section V.F of this action describes the limitations of the food sampling data and also describes plans for including perchlorate as part of the FDA's Total Diet Study. EPA requests that commenters provide the Agency with any additional data that may further characterize the concentrations of perchlorate in foods commercially available in the U.S. When providing data to the Agency, please describe the specific locations where the samples were collected, including geographic location, type of location (e.g., grocery store, farmer's market, commercial field, home garden), and the methodologies used to select, collect, prepare, and analyze the samples. Please include available laboratory data reports as well as all relevant quality assurance/quality control information. BILLING CODE 6560-50-P EP01MY07.052 EP01MY07.053 EP01MY07.054 BILLING CODE 6560-50-C a. *FDA Targeted Sampling.* The FDA released data on perchlorate in milk, lettuce, and bottled water in November 2004. To analyze food samples, FDA used ion chromatography (IC)-tandem mass spectrometry (MS/MS), referred to as IC-MS/MS. The quantitation limits for perchlorate in these analyses were 0.5 μg/L for bottled water, 1 μg/kg by fresh weight
(FW)for lettuce, and 3 μg/L for dairy milk. The mean concentration of perchlorate in 128 lettuce samples collected in 5 states (AZ, CA, FL, NJ, TX) was 10.3 μg/kg FW (FDA, 2004), and ranged from not quantifiable
(NQ)to 129 μg/kg FW. The mean concentrations of perchlorate in several varieties of lettuce are reported in Table 4. The mean concentration of perchlorate in 104 dairy milk samples collected in 14 states (AZ, CA, GA, KS, LA, MD, MO, NJ, NC, PA, SC, TX, VA, WA) was 5.76 μg/L (FDA, 2004), with a range from NQ to 11.3 μg/L. FDA
(2004)detected perchlorate in 2 of the 51 bottled water samples representing 34 distinct sources collected in 12 states (CA, CO, GA, MD, MN, MO, NC, NE, PA, SC, TX, WI) at levels of 0.56 μg/L and 0.45 μg/L. b. *Other Published Studies.* Sanchez
(2004)and Sanchez *et al.* (2005a) report the results of an analysis of agricultural products sampled from the lower Colorado River region of Arizona and California, the Imperial Valley of California, and the Coachella Valley of California, where irrigation water is known or suspected to contain perchlorate. The studies were partially supported by the U.S. Department of Agriculture—Agricultural Research Service (USDA-ARS). Samples of iceberg, romaine, and leaf lettuce, carrots, onions, sweet corn, squash, melons, tomatoes, peppers, broccoli, cauliflower, cabbage, durum wheat, and alfalfa were analyzed for perchlorate using ion chromatography
(IC)as the primary analytical method. For these analyses, the fresh-weight method reporting limit was not identified in most cases, but was reported to range from 20 to 50 μg/kg FW, depending on the moisture content of the samples (Sanchez, 2004). Sanchez *et al.* (2005a) report that the method reporting level for iceberg lettuce was approximately 20 μg/kg FW and for other types of lettuce was 25-30 μg/kg FW. Perchlorate in the irrigation water ranged from 1.5 to 8.0 μg/L over the period of the survey (Sanchez *et al.* , 2005a). Sanchez *et al.* (2005a) analyzed 44 samples of iceberg lettuce heads that had been trimmed of frame and wrapper leaves, which are usually removed before the lettuce is consumed. Perchlorate was quantified in 5 of the samples (ranging from 23 to 26 μg/kg FW), 23 perchlorate was not detectable in 6 samples, and the results of the remaining samples were less than the method reporting limit, which the authors defined as “a detectable peak among duplicates and/or replicates but below a level that can be quantitated.” Perchlorate concentrations in 10 samples of romaine and green leaf lettuce ranged from less than the method reporting limit to 81μg/kg FW (Sanchez, 2004). 23 Sanchez
(2004)presents somewhat different results. Specifically, of the 44 samples of “edible head” lettuce, perchlorate was quantified in one of the samples (26 μg/kg), perchlorate was not detectable in 6 samples, and the remaining sampling results were qualified as <MRL, which the author defined as “represents a seemingly detectable peak but below a level that can be quantitated.” As shown in Table 4, Sanchez
(2004)also detected perchlorate in samples of melons, tomatoes, and peppers, but at levels below the method reporting limit. Perchlorate was not detected in carrots, onions, sweet corn, squash, and durum wheat. Concentrations of perchlorate in 10 samples of alfalfa ranged from 109 to 668 μg/kg FW. Six of the 10 alfalfa samples were sent to FDA for confirmatory analysis by IC-MS/MS. The FDA results were generally lower than those of the corresponding samples by Sanchez (2004), ranging from 121 to 382 μg/kg FW. Sanchez *et al.*
(2006)conducted studies to evaluate the uptake and distribution of perchlorate in citrus trees and the occurrence of perchlorate in lemons, grapefruit, and oranges grown in southern California and southwestern Arizona. Five whole lemon trees irrigated with Colorado River water were harvested for destructive sampling. Sanchez *et al.*
(2006)estimate that the irrigation water had an average perchlorate concentration of 6 μg/L. Most of the sample analysis was conducted using IC-MS/MS, having an MRL of approximately 25 μg/kg by dry weight (DW). In samples of tree trunks, roots, and branches, perchlorate was close to or below the MRL. Perchlorate was much higher in the leaves than the fruit (peel and pulp), with mean concentrations of 1,835 and 128 μg/kg DW, respectively. Citrus samples were collected during 2004-2005 from the lower Colorado River Valley, the University of Arizona Research Farm, the Coachella Valley, and Los Angeles County. All analyses of fruit pulp were conducted using IC-MS/MS with an approximate MRL of 2.5 μg/kg FW. For the 86 citrus samples collected, the perchlorate concentration in the fruit pulp ranged from below detection to 37.6 μg/kg FW. Mean concentrations in lemons (33 samples), grapefruit (15 samples), and oranges (28 samples) were 2.3, 3.3, and 7.4 μg/kg FW, respectively. Sanchez *et al.* (2005b) surveyed perchlorate occurrence in lettuce and other leafy vegetables produced outside the lower Colorado River region. Samples were analyzed by IC, with a minimum reporting level of approximately 20 to 40 μg/kg FW, depending on the leafy vegetable type. Results of some of the more heavily sampled food items are presented in Table 4. While not shown in Table 4, Sanchez *et al.* (2005b) performed additional analysis by partitioning the leafy vegetable samples by type of culture. Perchlorate was detected in 70 of 268 samples of conventionally-grown leafy vegetables and 72 of 170 samples of organically-grown leafy vegetables. The range of perchlorate concentrations was ND to 104 μg/kg FW in conventional leafy vegetables and ND to 628 μg/kg FW in organic leafy vegetables. Sanchez *et al.* (2005b) analyzed the results using regression analysis and estimated that the median perchlorate concentration in organically-grown samples was 2.2 times higher than in conventionally-grown samples. The regression analysis also suggested that variation among sampling locations was greater than variation among lettuce types. Researchers at Texas Tech University analyzed samples of dairy and soy milk using IC and/or IC/MS analytical methods with detection limits of 1 μg/L or better (Kirk *et al.* , 2005). In a study of perchlorate in dairy milk, Kirk *et al.*
(2005)found mean perchlorate levels of 2.0 μg/L in 47 retail dairy milk samples from 11 states (AK, AZ, CA, FL, HI, KS, ME, NH, NM, NY, PA), with a range from not detected
(ND)to 11.0 μg/L. A single sample of soy milk was analyzed and reported to contain 0.7 μg/L perchlorate (Kirk *et al.* , 2005). An earlier study by Kirk *et al.*
(2003)found perchlorate ranging from 1.7 μg/L to 6.4 μg/L in 7 dairy milk samples purchased in a city in Texas. Jackson *et al.*
(2005)conducted limited sampling of edible and forage vegetation in 1 Texas county and in 1 Kansas home garden. In Texas, wheat and alfalfa were sampled from commercial fields irrigated with groundwater containing perchlorate from an unknown source, and a cucumber was sampled from an irrigated home garden. In Kansas, cantaloupe, cucumber, and tomatoes were sampled from an irrigated home garden near a slurry explosives site. Researchers used IC for sample analysis but did not report fresh-weight detection limits. Perchlorate was detected in all 12 samples of winter wheat heads (whole, including the chaff) at a mean concentration of 2,000 μg/kg FW but perchlorate was not detected in wheat endosperm (2 samples) 24 . The mean perchlorate concentration in 3 samples of alfalfa was 2,900 μg/kg FW. A cucumber sample from a Texas home garden contained 40 μg/kg FW perchlorate; a sample of irrigation water from this garden contained 20.7 μg/L perchlorate. In the Kansas home garden, the cucumber sample contained 770 μg/kg FW perchlorate, the cantaloupe sample contained 1,600 μg/kg FW perchlorate, and 2 samples of tomato contained 42 and 220 μg/kg FW perchlorate. The reported concentration of perchlorate in irrigation water for the Kansas home garden was 81 μg/L. EPA notes that the perchlorate levels in irrigation water samples associated with these two home gardens were significantly higher than in the vast majority of surface and ground water samples in the US. 24 A wheat kernel
(seed)has three major parts—the bran, the germ, and the endosperm. The majority of the wheat kernel is the endosperm, which is the portion of the kernel that is retained in refined (white) wheat flours. Whole wheat flours contain endosperm, wheat bran, and wheat germ in approximately the same proportions as in the wheat kernel. Wheat flours do not contain the chaff (husk). Aribi *et al.*
(2006)developed an analytical method for perchlorate that uses ion chromatography with suppressed conductivity and electrospray ionization tandem mass spectrometry (IC-ESI-MS/MS). The method was used to measure perchlorate in samples of various food products, including fresh/canned fruits and vegetables, wine, beer, and other beverages. Most samples were purchased in grocery and liquor stores in greater Toronto, Canada, between January 2005 and February 2006. Produce samples originated from many different parts of the world and all samples contained measurable amounts of perchlorate. However, the survey was limited to only a few samples of each food. Products from California, Chile, Costa Rica, Guatemala, and Mexico had the highest levels of perchlorate. Products from Canada and China had the lowest levels of perchlorate. The highest detection was in cantaloupe from Guatemala (463.50 μg/kg FW). Analysis of raw asparagus (39.900 μg/kg FW) and cooked asparagus (24.345 μg/kg FW) demonstrated that perchlorate can remain in food processed at a high temperature. Perchlorate concentrations in 8 samples of produce from the U.S. ranged from 0.094 μg/kg FW (for blueberries) to 19.29 μg/kg FW (for green grapes). *Aribi et al.*
(2006)analyzed 77 samples of wine and 144 samples of beer from many parts of the world. All samples contained measurable amounts of perchlorate. The wine sample with the single highest concentration of perchlorate, 50.250 μg/L, was from Portugal. Overall, wine samples from Chile contained the highest concentrations of perchlorate, ranging from 5.358 to 38.88 μg/L in 8 samples. Twelve samples of wine from the U.S. contained perchlorate concentrations ranging from 0.197 to 4.593 μg/L. Results from analysis of beer samples varied substantially among countries, with an overall range from 0.005 μg/L (Ireland) to 21.096 μg/L (France). Concentrations of perchlorate in 8 beer samples from the U.S. ranged from 0.364 to 2.014 μg/L. Snyder *et al.*
(2006)measured perchlorate in dietary supplements and flavor enhancing ingredients collected from various vendors in Las Vegas, NV, and Seattle, WA. Analyses were performed using LC-MS/MS with a limit of detection between 2 and 5 μg/kg. Perchlorate was detected in 20 of 31 analyzed supplements, with detectable concentrations ranging from 10 to 2,420 μg/kg. Based on manufacturers' recommended intake of the supplements, the resulting daily oral doses of perchlorate would range from 0.03 to 18 μg/day. Twelve of the supplements tested were prenatal or children's vitamins. The highest level of perchlorate (2,420 μg/kg or 0.018 mg/day at the recommended daily dose) was found in a prenatal vitamin; in the remaining prenatal and children's vitamins perchlorate did not exceed 28 μg/kg. The study noted that “vitamin and mineral supplements are typically formulated to include the Recommended Daily Allowance
(RDA)of iodine, a factor that would provide protection against any possible impacts of microgram levels of perchlorate found in these supplements.” Perchlorate was also detected at 740 μg/kg in a sample of kelp granules (a flavor enhancer), which equates to 2.2 μg perchlorate per serving. Martinelango *et al.* (2006a) measured perchlorate in seaweed, which is often used as a source of iodide in food and nutritional supplements. Martinelango *et al.* (2006a) collected samples of 11 different species of seaweed growing off the coast of northeastern Maine. Perchlorate was detected in all species, with concentrations ranging from 29 to 878 μg/kg DW. The iodide content in the samples was much higher, ranging from 16 to 3,134 mg/kg DW. Martinelango *et al.* (2006a) found that samples of *Laminaria* species concentrated iodide more selectively than perchlorate. Laminaria is a genus of large brown seaweeds that are commonly used in kelp tablets. Martinelango *et al.* (2006a) also analyzed 4 seaweed samples that had been washed with deionized water and found that a single wash removed 38 to 73 percent of the perchlorate and 34 to 44 percent of the iodide. D. Occurrence Studies on Perchlorate in Human Urine, Breast Milk, and Amniotic Fluid Recently researchers have used the results of the analysis of urine samples to estimate human exposure to perchlorate. Ingested perchlorate is not metabolized by humans and is excreted largely in the urine (Merrill *et al.* , 2005). The CDC's National Center for Environmental Health
(NCEH)developed a sensitive and selective analytical method to analyze perchlorate in human urine (Valentin-Blasini *et al.* , 2005). The method uses ion chromatography coupled with electrospray ionization tandem mass spectrometry (IC/MS/MS) and achieves an MRL of 0.025 μg/L in human urine. The authors report that the method is robust enough to process first-morning-void urine samples, which are samples of the first voiding of urine upon waking. Valentin-Blasini *et al.*
(2005)analyzed urine samples from 61 healthy adult donors who lived in the area of Atlanta, Georgia. The urine samples were provided anonymously, without associated donor information. Perchlorate was detected in all of the urine samples, with concentrations ranging from 0.66 to 21 μg/L. The authors cited dietary exposure as a potential source of perchlorate because perchlorate was found only at low levels (0.1—0.2 μg/L) in area tap water samples (Valentin-Blasini *et al.* , 2005). Valentin-Blasini *et al.*
(2005)also analyzed the urine samples for creatinine, which is a metabolic breakdown product in muscles that is eliminated from the body in urine at a predictable rate. When adjusted for urinary creatinine content, the reported range of perchlorate in the samples is 1.0 to 35 μg of perchlorate per gram of creatinine. The median perchlorate concentration was 3.2 μg/L (7.8 μg/g creatinine). The researchers stated that only 1 sample from the Atlanta population contained perchlorate at a level slightly in excess of the amount expected to be excreted by an individual exposed to perchlorate at the reference dose of 0.0007 mg/kg/day (Valentin-Blasini *et al.* , 2005). Specifically, assuming that perchlorate is excreted uniformly in urine throughout the day, a urinary excretion level of 34 μg perchlorate per gram creatinine would be associated with a daily perchlorate intake of 0.0007 mg/kg/day, for a 70 kg male that excretes creatinine at a typical rate of 1.44 grams per day (g/day). These assumptions are imprecise for individual exposure assessment but allow for spot urine perchlorate excretion to be related to the reference dose for toxicological perspective. Estimating perchlorate exposure from a single spot urine sample (as opposed to a sample collected continuously over a period of time) is imprecise due to the episodic nature of perchlorate exposure and the short half-life of perchlorate in the human body. The precision of estimated individual perchlorate exposure can be improved by more precise estimation of 24-hour creatinine excretion based on sex, height, weight, and age as described by Mage *et al.* (2004). In addition, imprecision stemming from the episodic nature of perchlorate exposure can be reduced with increased sampling. The analytical method developed by Valentin-Blasini *et al.*
(2005)was further used by Blount *et al.* (2006a) to evaluate urine samples from 27 volunteers with differing dietary habits. Blount *et al.* (2006a) collected first-morning-void urine specimens from volunteers living in the Atlanta area. The study volunteers self-assessed their consumption of milk, dairy products, and green/leafy vegetables within the 16 hours before the sample was collected. The samples were grouped into 2 categories (“one or fewer servings” and “three or more servings”) based on total consumption of these selected foods. Total daily perchlorate exposure was calculated using a bodyweight of 70 kg and a creatinine excretion rate of 1.44 g/day, assuming that each first-morning void urine sample was representative of that individual's daily perchlorate exposure. Each volunteer also collected a drinking water sample from home and work. Blount *et al.* (2006a) analyzed drinking water samples with the same method used for urine analysis and estimated exposure from drinking water based on a body weight of 70 kg and daily consumption of 2 liters of water per day. The mean creatinine-adjusted urinary perchlorate level was 1.8 times higher for individuals who identified themselves as consuming three or more servings of milk, dairy products, and/or green/leafy vegetables (6.13 versus 3.45 μg/g creatinine). There were no significant differences in the perchlorate levels in the drinking water samples of the 2 diet groups, which ranged from <0.05 to 0.25 μg/L with a median of 0.10 μg/L. Using a median drinking water level of 0.10 μg/L, Blount *et al.* (2006a) estimated that the perchlorate dose from drinking water was 0.003 μg/kg/day. Compared to this drinking water estimate, the total perchlorate dose estimate based on mean urinary perchlorate excretion was 24 times higher (0.071 μg/kg/day) and 42 times higher (0.126 μg/kg/day) for the low-consumption and high-consumption diet groups, respectively. The overall range of perchlorate found in urine was 0.94 to 17 μg/g creatinine with a median of 4.2 μg/g creatinine. In the largest study of its kind, Blount *et al.* (2006c) measured perchlorate in urine samples collected from a nationally representative sample of 2,820 U.S. residents, ages 6 years and older, as part of the 2001-2002 NHANES. Blount *et al.* (2006c) detected perchlorate at concentrations greater than 0.05 μg/L in all 2,820 urine samples tested, with a median concentration of 3.6 μg/L (3.38 μg/g creatinine) and a 95th percentile of 14 μg/L (12.7 μg/g creatinine). Only 0.7% of the study participants had an estimated perchlorate dose in excess of 0.0007 mg/kg/day. Women of reproductive age (15-44 years) had a median urinary perchlorate concentration of 2.9 μg/L (2.97 μg/g creatinine) and a 95th percentile of 13 μg/L (12.1 μg/g creatinine). The demographic with the highest concentration of urinary perchlorate was children (6-11 years), who had a median urinary perchlorate concentration of 5.2 μg/L (5.79 μg/g creatinine). Blount *et al.* (2006c) estimated a total daily perchlorate dose for each adult and found a median dose of 0.066 μg/kg/day (about one tenth of the RfD) and a 95th percentile of 0.234 μg/kg/day (about one third of the RfD). Eleven adults (0.7%) had estimated perchlorate exposure in excess of the RfD (0.7 μg/kg/day). The highest estimated exposure was 3.78 μg/kg/day. Because of daily variability in diet and perchlorate exposure, and the short residence time of perchlorate in the body, these single sample measurements may overestimate long-term average exposure for individuals at the upper end of the distribution and may underestimate the long-term average exposure for individuals at the lower end of the distribution. Daily perchlorate dose is not presented for children and adolescents due to the limited validation of formulas for these age groups (Blount *et al.* , 2006c). Valentin-Blasini *et al.*
(2005)and Téllez *et al.*
(2005)analyzed urine samples of pregnant women in 3 cities in Chile and found higher median levels of urinary perchlorate in cities with higher concentrations of perchlorate in tap water. Based on an assessment of drinking water intake, the researchers determined that, in all 3 cities, there was an additional source of perchlorate for the study participants that may be explained by dietary
(food)intake (Téllez *et al.* , 2005). This gap between estimated perchlorate exposure and perchlorate intake from tap water consumption ranged from 21.7 μg/day to 33.8 μg/day in the 3 Chilean cities (Téllez *et al.* , 2005). Martinelango *et al.* (2006b) developed a method to measure perchlorate in human urine with a limit of detection of 0.080 μg/L, and reported analytical results of 9 spot urine samples from male and female volunteers. Perchlorate was present in all samples analyzed, at concentrations ranging from 2.2 to 14.9 μg/L, with a median value of 8.1 μg/L. Other studies have investigated perchlorate in human breast milk. Kirk *et al.*
(2005)analyzed 36 breast milk samples from 18 states (CA, CT, FL, GA, HI, MD, ME, MI, MO, NC, NE, NJ, NM, NY, TX, VA, WA, WV) and found perchlorate concentrations in all samples ranging from 1.4 to 92.2 μg/L in all samples, with a mean concentration of 10.5 μg/L. Téllez *et al.*
(2005)report maternal parameters for participants from the study in Chile. Breast milk samples indicated that a significant amount of perchlorate leaves the body of the nursing mother through breast milk, in addition to urine. However, the breast milk perchlorate levels were highly variable and no significant correlations could be established between breast milk perchlorate and either urine perchlorate or breast milk iodide concentrations for the individuals evaluated in these Chilean cities (Téllez *et al.* , 2005). Kirk *et al.*
(2006)evaluated variations of iodide, thiocyanate and perchlorate in human milk samples. These authors suggest that if the overall intake of iodide is sufficient, it is unlikely that milk with an occasional low iodide or high perchlorate content would pose a major risk to infants. However, their limited data (evaluating only 10 women) show that the milk of some women may not supply infants with adequate iodide and they suggest that it may be important to base risk assessments for perchlorate exposure on the iodide to perchlorate ratio or the ratio of iodide to a “selectively-weighted sum of iodide uptake inhibiting agents.” Blount and Valentin-Blasini
(2006)developed a sensitive and selective method for quantifying iodide, perchlorate, thiocyanate, and nitrate in human amniotic fluid. The analytical limit of detection for perchlorate was calculated to be 0.020 μg/L. Samples of amniotic fluid at 15 to 20 weeks gestation were collected from 48 healthy women in an Eastern U.S. city for analysis. Perchlorate was found in all samples tested and exhibited a log-normal distribution. The perchlorate concentrations ranged from 0.057 to 0.71 μg/L with a median value of 0.18 μg/L. E. Status of the Preliminary Regulatory Determination for Perchlorate As stated earlier, the Agency is not making a preliminary regulatory determination for perchlorate in this notice. The Agency believes that additional information is needed on the sources of human exposure if it decides to base its determination regarding health risk reduction potential on a health reference level
(HRL)derived from the RfD and the relative source contribution
(RSC)for drinking water. Under this approach, the Agency would use the RfD and RSC to estimate an HRL and then use this HRL as a benchmark against which to conduct an evaluation of the occurrence data. In conducting such an assessment for the 6 non-carcinogens discussed previously in this action, EPA used a 20 percent RSC, which is the lowest and most conservative RSC used to estimate an HRL. Since the initial screening of the occurrence data against the HRL resulted in a preliminary negative determination, the Agency found that it was not necessary to further evaluate the RSC for these contaminants. In the case of perchlorate, the Agency is not at the point of being able to make either a negative or a positive determination using this approach because it is not yet clear what an appropriate RSC for perchlorate is. If EPA were to use a default RSC of 20% for perchlorate, the resulting HRL would be 5 μg/L. Approximately 3.16% of the 3,858 PWSs in the UCMR1 data set had at least one detect of perchlorate greater than or equal to 5 μg/L. Given this level of occurrence at the default-derived HRL, the Agency believes a better informed RSC and HRL would be needed to use this approach to determine whether regulation of perchlorate in drinking water presents a meaningful opportunity for health risk reduction. Table 5 shows the number of systems and population served that would exceed the HRL under various RSC scenarios and the sensitivity of this estimate to relatively small changes in the estimated RSC. For example, increasing the RSC from 20 to 30 percent would lower the estimated number of systems impacted by about a third and the estimated population served by about half. Hence, the choice of an appropriate RSC and resulting HRL could impact EPA's determination of whether regulation of perchlorate represents a meaningful opportunity for health risk reduction if it uses this approach. EPA recognizes that system-level population estimates shown in Table 5 may be conservative because some systems have multiple entry points to the distribution system and not all entry points had a positive detection for perchlorate in the UCMR 1 survey. Hence, to derive a less conservative population estimate (last column in Table 5), EPA assumed that the population for each system is equally distributed over all of the entry (or sampling) points and estimated a population-served value based on entry points that had at least 1 analytical detection for perchlorate at levels greater than each of the HRL thresholds. Table 5.—UCMR 1 Occurrence and Population Estimates for Perchlorate at Various HRL Thresholds a RSC scenarios (percent) Estimated HRL thresholds based on various RSC scenarios b PWSs with at least 1 detection > threshold of interest PWS entry or sample points with at least 1 detection > threshold of interest c Population served by PWSs with at least 1 detection > threshold of interest d Population estimate for entry or sample points having at least 1 detection > threshold of interest e 20 5 μg/L 3.16% (122 of 3,858) 1.88% (281 of 14,984) 14.6 M 4.0 M 30 7 μg/L 2.13% (82 of 3,858) 1.14% (171 of 14,984) 7.2 M 2.2 M 40 10 μg/L 1.35% (52 of 3,858) 0.65% (97 of 14,984) 5.0 M 1.5 M 50 12 μg/L 1.09% (42 of 3,858) 0.42% (63 of 14,984) 3.6 M 1.2 M 60 15 μg/L 0.80% (31 of 3,858) 0.29% (44 of 14,984) 2.0 M 0.9 M 70 17 μg/L 0.70% (27 of 3,858) 0.24% (36 of 14,984) 1.9 M 0.8 M 80 20 μg/L 0.49% (19 of 3,858) 0.16% (24 of 14,984) 1.5 M 0.7 M 100 25 μg/L 0.36% (14 of 3,858) 0.12% (18 of 14,984) 1.0 M 0.4 M Footnotes: a These data represent summary statistics for the 3,858 public water systems that have sampled for perchlorate as a part of the UCMR 1 survey. b HRL threshold = [(RfD of 0.0007 mg/kg/day x 70 kg BW for pregnant female) / (2 L DWI)] x the RSC scenario. Each HRL threshold value is converted from mg/L to μg/L units and then rounded to the nearest whole number. c The entry/sample-point-level population served estimate is based on the system entry/sample points that had at least 1analytical detection for perchlorate greater than the HRL threshold of interest. The UCMR 1 small system survey was designed to be representative of the nation's small systems, not necessarily to be representative of small system entry points. d The system-level population served estimate is based on the systems that had at least 1analytical detection for perchlorate greater than the HRL threshold of interest. e Because the population served by each entry/sample point is not known, EPA assumed that the total population served by a particular system is equally distributed across all entry/sample points. To derive the entry/sample point-level population estimate, EPA summed the population values for the entry/sample points that had at least 1 analytical detection greater than the threshold of interest. Table 5 also includes information on the effects of using an RSC of 100% (that is, using an HRL set at the DWEL of 24.5 μg/L, rounded to a whole number). Crawford-Brown *et al.* (2006), in an estimate of risk variability from perchlorate exposure through community water systems, noted that the subjects in the original 2002 Greer *et al.* , study (on which the RfD of .0007 mg/L was based) presumably had other sources of perchlorate exposure outside of the study and suggested that it may be appropriate to view their results as reflecting the effects of incremental exposure to perchlorate above the background levels already in food and water rather than the effects of total exposure, as is implicitly assumed when the HRL is derived using an RSC to account for other sources of exposure. Use of an RSC to derive the HRL is clearly appropriate when the RfD or cancer slope factor is derived from animal studies with carefully controlled exposure. Crawford-Brown *et al.* suggest, however, that an RSC is not necessary for perchlorate because there is no reason to assume that the background exposure of the study subjects was different than that of the general population. EPA notes that the sample size in the Greer study was small and EPA is not aware of data on their background exposure to perchlorate or how representative it may be. EPA requests comment on whether information is available on the background exposure of subjects in the Greer study and whether it should consider the background exposure of these subjects in determining an HRL for perchlorate. While several States have recommended guidelines or public health goals for perchlorate, EPA recognizes that at least 1 state, Massachusetts, 25 has already promulgated a final drinking water standard for perchlorate, that other States may set drinking water standards in the future, and that these standards could impact national occurrence estimates once these standards are fully implemented. 25 Massachusetts promulgated a final drinking water standard of 2 μg/L for perchlorate on July 28, 2006. For more information about the final standard, see *http://www.mass.gov/dep/public/press/pchl0706.htm* (MA DEP, 2006). F. What Are the Potential Options for Characterizing Perchlorate Exposure and Proceeding With the Preliminary Regulatory Determination for Perchlorate? While the Agency recognizes that food and other pathways may be important sources of perchlorate exposure, the Agency believes the currently available food data (summarized in section V.C.3) are inadequate to develop a better informed RSC (and HRL). First, some of the existing data are limited in their sample numbers, geographic coverage, and analytical method adequacy. Second, the current studies provide little or no data for several food groups ( *e.g.* , meat, poultry, fish, eggs, root and tuber vegetables, brassica vegetables, bulb vegetables, tree fruits, legumes, and cereal grains) that account for about half of the diet (by mass) for females of reproductive age (mid-teens to mid-forties). This section presents and requests comment on data EPA might use to estimate an RSC based on food-borne exposure as well as on several other options that the Agency is considering to better characterize perchlorate exposure and assist the Agency in making its regulatory determination for perchlorate. These options could serve as a supplement or an alternative to developing an HRL based on a better informed RSC derived from food concentration and consumption data. The Agency specifically seeks comment on the use of urine biomonitoring data in estimating perchlorate exposure. If the Agency decides to use any of the approaches discussed in V.F.2, EPA will need to determine what statistics ( *e.g.* , mean, median, percentile, etc.) are most appropriate for consideration in a regulatory determination. The Agency will also conduct a peer review, as appropriate, of any new methodology it decides to use. The Agency also invites the public to submit relevant data that may further characterize exposure to perchlorate through consumption of foods and/or through other pathways. The Agency will consider any new, relevant information/data provided in response to this action as the Agency determines whether to regulate perchlorate with a national primary drinking water regulation. 1. Use of Food Concentration and Consumption Data to Estimate an RSC. In the past, the Agency has relied on dietary exposure information from the FDA Total Diet Study
(TDS)to determine the RSC allowed for drinking water and to set health goals ( *i.e.* , Maximum Contaminant Level Goals) for several inorganic compounds ( *e.g.* , antimony, cadmium, chromium, and selenium). Under the TDS, foods are sampled at retail outlets, prepared as they would be consumed, and analyzed for a variety of analytes ( *e.g.* , nutrients, pesticides, industrial chemicals). Approximately 280 foods, covering a broad spectrum of the diet, are currently sampled in each sampling event. Sampling events (known as “market baskets”) occur about 4 times per year, with each event being confined to 1 of the 4 regions of the country. The dietary intake of the analyzed compounds can be calculated for the U.S. population by multiplying the concentrations found in TDS foods by the consumption amounts for each food. FDA compiles food consumption amounts for the total U.S. population by gender and by age group. 26 26 Information about FDA's TDS design, food list, analytes, and analytical results can be found at *http://www.cfsan.fda.gov/~comm/tds-toc.html.* (FDA, 2006) FDA is including perchlorate as an analyte in the 2006 TDS. EPA believes that a comprehensive dietary intake estimate for perchlorate will be useful in evaluating dietary exposure relative to drinking water. When sufficient quantitative exposure data are available (such as the data published by FDA in conjunction with the TDS), EPA can use the procedure used previously for several regulated inorganic compounds ( *i.e.* , chromium and selenium) to calculate the relative source contribution for perchlorate. In these cases where dietary intake values were available, EPA subtracted the dietary intake value from the Drinking Water Equivalent Level DWEL and used the remainder as the allowance for water. This procedure assures that total exposure does not exceed the RfD. The Agency invites the public to submit relevant data that may further characterize exposure to perchlorate through consumption of foods and/or through other pathways. This information may help the Agency in the evaluation of currently available food data and the 2006 TDS. 2. Use of Urinary Biomonitoring Data to Evaluate Exposure to Perchlorate. Researchers at CDC's National Center for Environmental Health
(NCEH)have conducted a large national study of total perchlorate exposure through analysis of urine samples collected for NHANES 2001-2002 (Blount *et al.* , 2006b and 2006c). The use of urinary perchlorate excretion to estimate perchlorate exposure has been demonstrated in Valentin-Blasini *et al.* (2005), Tollez *et al.* (2005), and Blount *et al.* (2006c). While this would be the first time the Agency has used biomonitoring data to assist EPA in making a preliminary regulatory determination for a CCL contaminant, the Agency believes that estimating perchlorate exposure among large populations using urinary perchlorate excretion data may be appropriate for the following reasons: • Perchlorate is not metabolized in the body and is excreted unchanged primarily via the renal pathway (Merrill *et al.* , 2005), • Perchlorate does not bioaccumulate, that is, it is excreted essentially completely (Merrill *et al.* , 2005), • Perchlorate has a short half-life in the human body (approximately 8 hours), simplifying the estimation of daily exposure (Greer *et al.* , 2002), and • A methodology exists that allows estimation of daily perchlorate intake from all sources ( *e.g.* , water, food) using standard creatinine adjustment factors to account for variations in urine concentration (Mage *et al.* , 2004). The Agency could use the 2001-2002 NHANES urine data in several ways as described in the following paragraphs. The Agency welcomes comment from the public on these approaches, as well as suggestions for other analyses that may inform the preliminary regulatory determination for perchlorate. One potential approach is to use the 2001-2002 NHANES urine data to directly determine whether regulation of perchlorate in drinking water presents a meaningful opportunity for health risk reduction. More specifically, we could use the urine data (as in Blount *et al.* , 2006b and c) to evaluate whether total exposure from food and water is likely to result in an appreciable risk of adverse health effects for the U.S. population. If the Agency concluded that total exposure, as estimated from the urine data, does not pose an appreciable risk, even at the upper end of the exposure distribution, then it would follow logically that reducing this exposure by regulating drinking water would not present a meaningful opportunity for health risk reduction. As summarized above, Blount *et al.* (2006c) estimated a median total daily perchlorate dose for adults of 0.066 μg/kg/day (about one tenth of the RfD) and a 95th percentile dose of 0.234 μg/kg/day (about one third of the RfD). Only eleven adults (0.7%) had an estimated dose in excess of the RfD (0.7 μg/kg/day). EPA requests comment on whether or not these data provide an adequate basis to support a regulatory determination for perchlorate. EPA also requests comment on the relevance, if any, to a regulatory determination for perchlorate, of the Blount et al (2006b) study, which showed an association between T4/TSH levels in women and urinary perchlorate concentrations at levels below the RfD (see Section V.B). EPA could also use the 2001-2002 NHANES urine data to qualitatively evaluate the importance of the water contribution to overall exposure. For this approach, the Agency could merge data from the 2001-2002 NHANES and UCMR 1 and compare the total perchlorate exposure values (based on the urine data) for the population of individuals whose drinking water contains perchlorate at various concentration levels, ranging from non-detect to the upper end of the occurrence distribution. The intent of this analysis would be to permit the Agency to determine whether total perchlorate exposure (as measured in urine) is meaningfully correlated with concentrations in local public drinking water supplies, though EPA would only use these results qualitatively because it is not possible to match up individual urine samples with individual drinking water exposures. However, the results could be useful in determining at least qualitatively the potential significance of drinking water exposure for total exposure. If there were not a significant correlation between public water system perchlorate occurrence and individual exposure as measured through biomonitoring, this might suggest that there is not a meaningful opportunity for health risk reduction through regulation of drinking water. The Agency could also potentially use the 2001-2002 NHANES urine data to derive an RSC to use for drinking water. This could potentially be done in several different ways as follows. a. *Use of Urinary Biomonitoring Total Exposure Value to Estimate an RSC* . One possible approach to estimating an RSC for water would be to use the urine data to estimate total perchlorate exposure, then subtract this exposure value from the reference dose and allow the remainder as the exposure limit for water. The allowed remainder divided by the RfD would be the RSC for drinking water. This approach would yield a conservative RSC value because the exposure used to represent food would actually correspond to both food and drinking water exposure, whereas, if it were possible to estimate the exposure from food alone, the relative amount allowed for water would be larger (resulting in a higher RSC and higher health reference value). As discussed in Section V.D, Blount *et al.* (2006c) estimated a total daily perchlorate dose for adults from urine data and found a median dose of 0.066 μg/kg/day (about one tenth of the RfD) and a 95th percentile of 0.234 μg/kg/day (about one third of the RfD). If EPA were to use the estimated 95th percentile total dose from the Blount study as if it represented the exposure from food alone, this would suggest a residual screening-level RSC of about 70% allocated to water. One possible limitation of this approach is that the Blount study estimates exposure for adults only. Therefore, an RSC developed based upon this data would not necessarily be representative of children. EPA requests comment on using this approach as the basis for deriving a screening-level RSC. b. *Use of the Urine Data and UCMR 1 to Deduce Exposure from Other Sources and Derive the RSC* . Alternately, for those NHANES survey subjects served by public drinking water systems with positive detections for perchlorate (based on UCMR 1), EPA could estimate the expected perchlorate dose contributed by drinking water (using individual water consumption data from the NHANES survey combined with UCMR 1 data for the area in which they live) and subtract it from the total perchlorate dose (based on urinary perchlorate excretion data) to calculate the amount contributed by food. Subtraction of this calculated food contribution from the RfD would yield the amount allowed for drinking water, which could be divided by the RfD to calculate an RSC. One limitation of this methodology would be the assumption that subjects in the NHANES study are uniformly consuming drinking water that contains perchlorate at the concentration indicated in the UCMR 1 data for their area. c. *Use of Urinary Biomonitoring Data from Exclusive Bottled Water Drinkers to Estimate an RSC* . The 2001-2002 NHANES data includes urinary perchlorate data for populations who exclusively drink bottled water. As noted in section V.C.3.a, FDA
(2004)tested 51 samples of bottled water from 34 distinct sources in 12 states and detected perchlorate in 2 samples (at levels of 0.56 μg/L and 0.45 μg/L). These levels are well below the MRL for the UCMR 1 data and would not contribute significant amounts of perchlorate relative to the RfD. If the population of exclusive bottled water drinkers is sufficiently representative of the U.S. population, these data potentially could be used to estimate the contribution of perchlorate exposure coming from food and allow the Agency to estimate an RSC for drinking water. The RSC value could be derived by subtracting the estimated perchlorate exposure for exclusive bottled water drinkers from the RfD of 0.0007 mg/kg/day, using the remainder as the allowance for drinking water. One limitation of this methodology is that the perchlorate concentration of the bottled water used by this NHANES population is not known. Hence, we would have to assume that the bottled water concentration data collected by FDA
(2004)is representative of the perchlorate concentration in the bottled water used by the NHANES exclusive bottled water population. Another limitation of this approach is that it would not subtract out the fraction of the drinking water intake that comes from water used for cooking purposes (since bottled water is probably not used by most subjects in cooking and household food preparation). It would thus produce a conservative (health protective) estimate of the RSC as it would overestimate the fraction of total exposure coming from food. G. Next Steps After the Agency evaluates and thoroughly reviews public comments and any new information/data on perchlorate obtained following this notice, and performs the necessary analyses, the Agency intends to move expeditiously to publish a preliminary regulatory determination for perchlorate. Depending on how quickly the Agency is able to complete the necessary analyses and determine the best approach for making this determination, EPA may be able to publish the preliminary determination in time to include a final determination for perchlorate as part of the final CCL 2 regulatory determination, which is due by July, 2008. If not, the Agency will publish its final determination for perchlorate as soon thereafter as possible. EPA does not intend to wait until the CCL 3 regulatory determination cycle to complete its determination for perchlorate. VI. What About the Remaining CCL 2 Contaminants? As previously stated, EPA is only making regulatory determinations on CCL 2 contaminants that have sufficient information to support a regulatory determination at this time. Section V discusses the status of EPA's review of perchlorate. For the 30 remaining chemicals and the 9 microbial pathogens, the Agency lacks adequate information in the areas of health effects or occurrence or both. The Agency continues to conduct research and/or to collect information on the remaining CCL 2 contaminants to fill identified data gaps. Stakeholders may be concerned that regulatory determinations for such contaminants should not necessarily wait until the end of the next regulatory determination cycle. In this regard, it is important to recognize that the Agency is not precluded from conducting research, monitoring, developing guidance or health advisories, and/or making a determination prior to the end of the next cycle. In addition, the Agency is not precluded from regulating a contaminant at any time when it is necessary to address an urgent threat to public health, including any contaminant not listed on the CCL. Because the focus of this action is to announce and solicit public comment on the Agency's preliminary determinations for 11 of the 51 CCL 2 contaminants, this action primarily provides information on these 11 contaminants. The Agency recognizes that the public may have a particular interest in metolachlor, methyl tertiary butyl ether (MTBE), and the microbial contaminants. Therefore, this action includes some additional information for these contaminants in the following sections and requests public comment on any further data, information and/or analyses that the Agency should be aware of. A. Metolachlor 1. Background. Metolachlor is a broad spectrum herbicide used for general weed control in many agricultural food and feed crops (primarily corn, soybeans and sorghum), on lawns and turf, ornamental plants, trees, shrubs and vines, rights of way, fencerows and hedgerows, and in forestry. Metolachlor appears to be moderately persistent to persistent and depending on the type of soil, can be highly mobile. Degradation of metolachlor in the environment is dependent on microbially-mediated and abiotic processes. Metolachlor has at least 5 major degradates. Two of the more common degradates are metolachlor ethane sulfonic acid
(ESA)and metolachlor oxanilic acid (OA). 2. Health. The Agency established an RfD for metolachlor of 0.1 mg/kg/day based on an NOAEL of 9.7 mg/kg/day and a UF of 100 (USEPA, 1995). The Agency derived the NOAEL from a one-year chronic feeding study in beagle dogs where the critical effect was decreased body weight gain. Metolachlor shows some evidence of causing developmental toxicity effects in rats but none in rabbits. The doses associated with the developmental effect in rats are greater than the NOAEL and therefore the NOAEL would be protective against developmental toxicity. Metolachlor has been evaluated for carcinogenic activity in both rats and mice. No treatment-related cancer effects were observed in 2 studies using mice. In studies using rats, metolachlor caused a significant increase in liver nodules and carcinomas in high dose females. Negative results from mutagenicity studies suggest that tumors may result from a nonmutagenic mode of action. In 1991, a peer review committee recommended that metolachlor be classified as a possible human carcinogen based on increases in liver tumors in the female rat. However, a peer review conducted in July 1994 recommended that the evidence for cancer was suggestive and should not be quantified. This recommendation was supported by negative mutagenicity data and recent metabolism data indicating that the formation of the metabolite presumed to be the ultimate carcinogen is very low (USEPA, 1995). 3. Occurrence. EPA included metolachlor as an analyte in the UCM Round 2 survey. EPA evaluated the UCM Round 2 Cross Section data and found that metolachlor was detected at or above the reporting limit of 0.1 μg/L in 0.83% of the 12,953 systems that sampled for metolachlor (USEPA, 2006a). The USGS NAWQA program included metolachlor as an analyte in its 1992-2001 monitoring survey of ambient surface and ground waters across the United States. EPA evaluated the results of the provisional data, which are available on the Web at *http://ca.water.usgs.gov/pnsp/* (Martin *et al.* , 2003; Kolpin and Martin, 2003). While the USGS detected metolachlor in both surface and ground waters, 95 percent of the samples from the various land use settings were less than 1.38 μg/L. The maximum surface water concentration is 77.6 μg/L (agricultural setting) and the maximum estimated ground water concentration is 32.8 μg/L (agricultural setting). 4. Consideration of the ESA and OA degradates. While EPA has health and occurrence information for metolachlor itself, the Agency believes it is prudent to also consider the occurrence and exposure of the ESA and OA degradates as well. At this time, there is no finished water occurrence and exposure information for these 2 degradates from a nationally representative sample of PWSs. However, a few small-scale studies indicate that the ESA and the OA degradates may be occurring at greater frequencies and at higher concentrations than the metolachlor parent (Phillips *et al.* , 1999a and 1999b; Rheineck and Postle, 2000). In order to gather more information about the occurrence of the ESA and OA degradates in finished water (along with the metolachlor parent), the Agency has added these degradates and their parent to the second unregulated contaminant monitoring regulation (UCMR 2; 70 FR 49093; USEPA, 2005g). While EPA awaits the results of the UCMR 2 survey, the Agency is planning to update the health advisory for metolachlor to include the ESA and OA degradates. The Agency requests comment from the public as to whether updating the health advisory to include these degradates will be useful for States and public water utilities. In addition, the Agency requests answers to the following questions and any available data: • Are States collecting data on the co-occurrence of metolachlor and its degradates in source waters on a state-wide basis? In drinking water on a state-wide basis? • If available, are States willing to provide data on the co-occurrence of metolachlor and its ESA and OA degradates in community and public water systems? What analytical method and reporting limit were used to gather these data? • Do States have any information on the number of PWSs impacted by metolachlor and/or its degradates? • Have States seen an increase or decrease in the number of PWSs impacted by metolachlor and/or its degradates? • How many systems have taken wells or sources offline due to impacts from metolachlor and/or its degradates? B. Methyl tertiary-butyl ether 1. Background Methyl tertiary-butyl ether
(MTBE)is a volatile organic compound synthesized for use as a gasoline additive. First used as an octane enhancer to improve engine performance, MTBE is also used to reduce emissions that form carbon monoxide and ozone. Leaking underground storage tanks, gasoline distribution facilities, and even recreational boating can release MTBE into the environment. In 1997, EPA issued a drinking water advisory of 20 to 40 μg/L based on taste and odor (USEPA, 1997b). EPA is currently revising its health risk assessment for MTBE, and thus, will not be making a regulatory determination for MTBE as part of this action. The IRIS Chemical Assessment Tracking System *http://cfpub.epa.gov/iristrac/index.cfm* has the most up-to-date information on the status of the MTBF health risk assessment and interested members of the public should check that Web site to find out the latest schedule. The Agency collected data on MTBE occurrence as part of the UCMR 1 survey. In addition, EPA evaluated several sources of supplemental occurrence information described in the supporting documentation for this action entitled “Regulatory Determinations Support Document for Selected Contaminants from the Second Drinking Water Contaminant Candidate List (CCL 2)” (USEPA, 2006a). Section VI.B.2 provides a summary of some of the data and information on MTBE occurrence collected to date. 2. Occurrence Information a. *UCMR 1.* EPA collected sampling results for MTBE from over 98.9 percent (3,068 of 3,100) of the large PWSs and over 99.5 percent (796 of 800) of the small systems required to sample under UCMR 1. Based on these data, 19 public water systems (0.49 percent of the 3,864 sampled) in 14 states (CA, CT, GA, IL, MA, MO, NH, NJ, NM, NY, PA, SD, TN, and WV) reported MTBE occurrence in drinking water. These 19 systems reported MTBE in 26 samples at the minimum reporting level of 5 μg/L or above, representing approximately 0.33 percent (or 754 thousand of 226 million) of the population served by the public water systems that sampled for MTBE. (USEPA, 2006a) Of the PWSs reporting detections at or above 5 μg/L (the MRL), 15 were ground water systems and 4 were surface water systems. One small ground water system (49 μg/L) and 3 large ground water PWSs (48 μg/L, 36 μg/L, and 33.2 μg/L) reported MTBE at levels greater than 20 μg/L (the lower end of the taste and odor threshold). One large surface water system (33 μg/L) reported MTBE at levels greater than 20 μg/L. The remaining 14 systems had detects between 5 μg/L and 20 μg/L (USEPA, 2006a). b. *USGS studies/surveys/reviews.* In 2003, the USGS reported results of national source water sampling (previously introduced in section III.B.2.a.(2)). USGS sampling included a random study of a representative sample of untreated source waters (known as the “Random Survey”) and a study of source waters from areas known or suspected of having MTBE (known as the “Focused Survey”). In the Random Survey, USGS found that none of the source waters exceeded 20 μg/L, and the three highest concentration sources ranged from 6 μg/L to 19.5 μg/L (Grady, 2003). Of the areas known or suspected of having MTBE in the Focused Survey, USGS found that 5 percent (e.g., ground waters for 7 of the 134 systems) had concentrations greater than 20 μg/L (Delzer and Ivahnenko, 2003a). USGS also reviewed the literature for national, regional, and State MTBE information (Delzer and Ivahnenko, 2003b), including 13 state-wide assessments. This information is summarized in Table 6. USGS noted that because study objectives varied, information varied in terms of reporting levels, sampling frequencies, and sources (e.g., ambient water, public and homeowner wells, treated drinking water). Previously, USGS (Grady and Casey, 2001) studied MTBE occurrence in the drinking water of 12 States (New England and the Mid-Atlantic). The study found less than 1 percent of the CWSs had drinking water samples at or above 20 μg/L, while 7.8 percent of the CWSs had MTBE at 1 μg/L or higher. BILLING CODE 6560-50-P EP01MY07.055 BILLING CODE 6560-50-C c. *New England Interstate Water Pollution Control Commission (NEIWPCC).* In 2003, the NEIWPCC surveyed the States under a grant from EPA's Office of Underground Storage Tanks (UST). Twenty-six States estimated that they had public wells that were contaminated by MTBE at some level, and of those, 5 States (ME, NH, NJ, DE, and MD) estimated having detectable levels of MTBE in at least 100 public water supply wells. Thirteen States did not know the answer, 8 States did not respond, and 3 States reported that no PWS wells were impacted. The survey established no reporting level to define “contamination.” Only 3 States documented the basis for their estimates (projected from several studies, raw and treated water analyses, and a survey of funded petroleum spill projects) (NEIWPCC, 2003). d. *California Department of Health Services.* In 2000, California developed a drinking water standard of 13 μg/L for MTBE (CA DHS, 2000). According to California's annual compliance reports, there were no violations of the 13 μg/L standard by public water systems in 2002 and 2003, and 2 violations at 2 public water systems (serving almost 14,000 people) in 2004 (CA DHS, 2002; CA DHS, 2003; CA DHS, 2004). e. *Other Sources of Data.* In April 2005, the Environmental Working Group (EWG, 2005) released a report, Like Oil and Water, on their Web page. In response to Freedom of Information Act requests, 29 State agencies submitted data to EWG. EPA informally evaluated the data posted by EWG to determine if this information might be useful in projecting state-wide occurrence. While EPA found the report interesting, the data as reported on the Web lacked some of the information needed to assess the representativeness and the quality of the data. For example, States submitted different time periods of monitoring data ( *e.g.* , Alaska submitted 7 months of data for 1 system during the 2000 timeframe and Illinois submitted data that spanned 1990 to 2002). States did not report monitoring results for every system. Also, the data do not indicate if the samples came from source water or finished water, from ground water or surface water, the analytical method used for analysis nor the reporting level, the frequency of the sampling ( *e.g.* , annual, quarterly), number of samples from each water system, number of non-detects, etc. 3. Request for Additional MTBE Occurrence Information As discussed earlier, EPA is not making a regulatory determination for MTBE; however, EPA is presenting this information because of ongoing interest in MTBE. And as noted earlier, additional information is presented in the regulatory support document for this action ( *i.e.* , USEPA, 2006a). While the Agency waits for the final health risk assessment, EPA will continue to collect and evaluate occurrence information. The Agency requests any data, information, or analyses that may be available on the following topics: • Are there additional occurrence data for MTBE in community and non-community public water systems on a state-wide or more local basis? As noted in the previous section, the State data submitted to EWG lack some elements needed to assess the quality of the data, as required in EPA's guidance for information quality guidelines (USEPA, 2003c), and project state-wide occurrence. • What analytical method and reporting limit were used to gather these data? • Has there been an increase or decrease in the number of impacted PWSs? Over what time frame? • For those PWSs whose water supplies have been impacted, has there been an increase or a decrease in the concentration of MTBE? • How many systems have taken wells or sources offline, consolidated with other PWSs, or added customers due to impacts from MTBE? • What treatments are being used in the field? What range of treatment effectiveness is being achieved? • Is the listing of State bans for MTBE shown in Table 7 complete? Have state-wide bans decreased MTBE contamination in drinking water? Table 7.—State Actions Banning MTBE (State-wide) [Adapted from USEPA, 2004g and McCarthy and Tiemann, 2005] State Effective date Extent of MTBE ban Arizona January 1, 2005 0.3% max volume in gasoline. California December 31, 2003 complete ban in gasoline. Colorado April 30, 2002 complete ban in gasoline. Connecticut January 1, 2004 complete ban in gasoline. Illinois July 24, 2004 0.5% max volume in gasoline. Indiana July 24, 2004 0.5% max volume in gasoline. Iowa July 1, 2000 0.5% max volume in gasoline. Kansas July 1, 2004 0.5% max volume in gasoline. Kentucky January 1, 2006 0.5% max volume in gasoline. Maine January 1, 2007 0.5% max volume in gasoline. Michigan June 1, 2003 complete ban in gasoline. Minnesota July 2, 2005 complete ban in gasoline. (following partial ban in 2000). Missouri July 1, 2005 0.5% max volume in gasoline. Montana January 1, 2006 no more than trace amounts in gasoline. Nebraska July 13, 2000 1% max volume in gasoline. New Hampshire January 1, 2007 0.5% max volume in gasoline. New Jersey January 1, 2009 0.5% max volume in gasoline. New York January 1, 2004 complete ban in gasoline. North Carolina January 1, 2008 0.5% max volume in gasoline. Ohio July 1, 2005 0.5% max volume in gasoline. Rhode Island June 1, 2007 0.5% max volume in gasoline. South Dakota July 1, 2001 0.5% max volume in gasoline. Vermont January 1, 2007 0.5% max volume in gasoline. Washington January 1, 2004 0.6% max volume in gasoline. Wisconsin August 1, 2004 0.5% max volume in gasoline. C. Microbial Contaminants 1. Evaluation of Microbial Contaminants for Regulatory Determination. The 9 microbial contaminants listed on CCL 2 include: • Four virus groups—Caliciviruses, Echoviruses, Coxsackieviruses, and Adenoviruses • Four bacteria/bacterial groups- *Aeromonas hydrophila; Helicobacter pylori; Mycobacterium avium intercellulare (or MAC);* and Cyanobacteria (called blue-green algae 27 ), fresh water algae, and the associated toxins 27 Cyanobacteria are called blue-green algae even though they are technically bacteria. • One group of protozoa—Microsporidia ( *Enterocytozoon bieneusi* and *Septata intestinalis,* now renamed *Encephalitozoon intestinalis* ). In addition to considering if the Agency had sufficient information to address the three statutory criteria listed in section II.B.1 (i.e., adverse health effects, known/likely occurrence, and meaningful opportunity for health risk reduction), the Agency also considered whether sufficient information was available to determine whether current treatment requirements adequately controlled for any of the 9 microbial contaminants. After consideration of these factors, the Agency determined that none of the 9 microbial contaminants have sufficient information at this time to address the three statutory criteria to make a regulatory determination. Table 8 identifies the specific areas for which information is insufficient. Table 8.—Information Gaps for the Microbial Contaminants Health effects Treatment Analytical methods Occurrence Microsporidia *Aeromonas* *Aeromonas* *Aeromonas.* Some Cyanotoxins *MAC* *MAC* *MAC.* Adenoviruses *Helicobacter* *Helicobacter.* Caliciviruses Microsporidia Adenoviruses. Coxsackieviruses Some Cyanotoxins Caliciviruses. Echoviruses Coxsackieviruses. Microsporidia Echoviruses. Some Cyanotoxins Microsporidia. *Helicobacter* Some Cyanotoxins. 2. Research and Other Ongoing Activities. EPA has supported an active research program to fill the information gaps on the CCL 2 microorganisms. While several examples of the ongoing research activities are listed below, further information on these and other projects can be found on EPA's Drinking Water Research Information Network (DRINK). DRINK is a publicly-accessible, Web-based system that tracks over 1,000 ongoing research projects and can be accessed at: *http://www.epa.gov/safewater/drink/intro.html.* a. *Virus.* For the CCL virus groups (or surrogates), the Agency has initiated treatment studies that simulate realistic conditions where viruses may be protected in aggregates. EPA also plans to conduct virus removal/inactivation studies in drinking water treatment plants and/or pilot plants. In order to assess the effectiveness of treatment and to perform monitoring studies, methods development for viruses is also in progress. b. *Bacteria.* For Aeromonas spp., EPA recently completed a one-year UCMR 1 survey of 293 public water systems. The Agency is currently attempting to characterize and distinguish pathogenic from non-pathogenic strains, as well as develop methods to detect Aeromonas virulence factors. For *H. pylori,* the Agency is in the process of developing a culture method and method for its identification. For *MAC,* preliminary drinking water surveys have been conducted using a culture method followed by genetic detection. EPA is also conducting further research into methods development and the characterization of virulence factors for this organism. EPA has funded projects to evaluate the effect of disinfectants on cyanotoxins, and on the removal of algal cells and cyanotoxins in a pilot scale treatment plant. EPA is developing analytical methods for potential use for future monitoring and has available analytical chemistry standards for the toxins of most concern in the United States—microcystin, cylindrospermopsin, and anatoxin-a. EPA has conducted several small-scale preliminary occurrence surveys for cyanotoxins using a screening method followed by confirmation by instrumental analysis. A number of health effects studies are also in progress on several high priority cyanotoxins. These include behavioral studies in mice, acute and subacute effects in neonatal mice, and biomarkers of human exposure. Risk assessments are being conducted at EPA on the cyanotoxins to determine reference doses where possible. The Agency has organized and participated in several workshops on cyanotoxins to assess the state-of-the-science. As an interim measure to assist public water utilities, the Agency is planning to develop an information sheet that discusses pertinent information on cyanobacteria and some of its key toxins. The document will discuss the state of the knowledge on the prevention and treatment of cyanobacteria and its toxins, as well as the available information on the potential health effects of some of the toxins. EPA requests comment from the public as to whether such a document would be useful for public water utilities. c. *Protozoa.* EPA has several ongoing projects to evaluate the susceptibility of microsporidia to chlorine and chloramine disinfectants. EPA has sponsored methods-related projects for microsporidia, which have included the use of fluorescent gene probes, real-time PCR, concentration methods, and immunomagnetic separation. Ongoing monitoring at EPA has revealed that microsporidia are present in ground water. EPA has funded work to determine exposure to microsporidia, and to determine strains (animal and human) of Enterocytozoon bieneusi found in water. EPA also held a workshop in 2003 on microsporidia to assess the state-of-the-science. VII. EPA's Next Steps EPA intends to respond to the public comments it receives on the 11 preliminary determinations and subsequently issue its final regulatory determinations. 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May, 1989. USEPA. 1990a. National Pesticide Survey: Survey Analytes. EPA Report 570-9-90-NPS2. Available on the Internet at: *http://nepis.epa.gov/pubtitleOSWER.htm.* [Search for document number 570990NPS2.] USEPA. 1990b. National Survey of Pesticides in Drinking Water Wells. Phase I Report. EPA Report 570-9-90-015. USEPA. 1990c. “Integrated Risk Information System (IRIS), 2,4-/2,6-Dinitrotoluene Mixture.” September 1990. Available on the Internet at: *http://www.epa.gov/iris/subst/0397.htm.* Accessed December 16, 2004. USEPA. 1990d. “Integrated Risk Information System (IRIS), S-Ethyl Dipropylthiocarbamate (EPTC).” September 1990. Available on the Internet at: *http://www.epa.gov/iris/subst/0237.htm.* Accessed February 2, 2005. USEPA. 1991. “Integrated Risk Information System (IRIS), Fonofos.” March 1991. Available on the Internet at: *http://www.epa.gov/iris/subst/0158.htm.* Accessed February 2, 2005. USEPA. 1992a. 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(DNT)Health Advisory. EPA Report 820-R-92-002. April 1992. USEPA. 1994. “Integrated Risk Information System (IRIS), Dacthal.” August 1994. Available on the Internet at: *http://www.epa.gov/iris/subst/0221.htm.* Accessed February 2, 2005. USEPA. 1995. Reregistration Eligibility Decision (RED)—Metolachlor. EPA Report 738-R-95-006. Washington, DC: USEPA Office of Prevention, Pesticides and Toxic Substances. April 1995. Available on the Internet at: *http://www.epa.gov/oppsrrd1/REDs/0001.pdf.* USEPA. 1996a. Proposed Guidelines for Carcinogen Risk Assessment. **Federal Register** . Vol. 61, No. 79. p. 17960, April 23, 1996. USEPA. 1996b. “Integrated Risk Information System (IRIS), p,p′-Dichlorodiphenyltrichloroethane (DDT).” February 1996. Available on the Internet at: *http://www.epa.gov/iris/subst/0147.htm.* Accessed February 2, 2005. USEPA. 1996c. Memorandum—041701. Fonofos (Dyfonate®). Draft Toxicology Chapter for Reregistration Eligibility. Health Effects Division. September 11, 1996. USEPA. 1997a. Announcement of the Draft Drinking Water Contaminant Candidate List; Notice. **Federal Register** . Vol. 62, No. 193. p. 52193, October 6, 1997. USEPA. 1997b. Drinking Water Advisory: Consumer Acceptability Advice and Health Effects Analysis on Methyl Tertiary-Butyl Ether (MTBE). EPA Report 822-F-97-009. December 1997. Available on the Internet at: *http://www.epa.gov/waterscience/drinking/mtbefact.pdf.* USEPA. 1998a. Announcement of the Draft Drinking Water Contaminant Candidate List; Notice. **Federal Register** . Vol. 63, No. 40. p. 10273, March 2, 1998. USEPA. 1998b. Reregistration Eligibility Decision (RED)—1,3-Dichloropropene. EPA Report 738-R-98-016. Washington, DC: Office of Prevention, Pesticides and Toxic Substances. December 1998. Available on the Internet at: *http://www.epa.gov/oppsrrd1/REDs/0328red.pdf.* USEPA. 1998c. Reregistration Eligibility Decision (RED)—DCPA. EPA Report 738-R-98-005. Washington, DC: Office of Prevention, Pesticides and Toxic Substances. November 1998. Available on the Internet at: *http://www.epa.gov/oppsrrd1/REDs/0270red.pdf.* USEPA. 1998d. Notice of Receipt of Requests to Voluntarily Cancel Certain Pesticide Registrations. **Federal Register** . Vol. 63, No. 87. p. 25033, May 6, 1998. USEPA. 1998e. Reregistration Eligibility Decision (RED)—Terbacil. EPA Report 738-R-97-011. Washington, DC: Office of Prevention, Pesticides and Toxic Substances. January 1998. Available on the Internet at: *http://www.epa.gov/oppsrrd1/REDs/0039red.pdf.* USEPA. 1999a. Guidelines for Carcinogen Risk Assessment. NCEA-F-0644, Review Draft. July 1999. Available on the Internet at: *http://www.epa.gov/iris/cancer_gls.pdf.* USEPA. 1999b. Revisions to the Unregulated Contaminant Monitoring Regulation for Public Water Systems. **Federal Register** . Vol. 64, No. 180. p. 50556, September 17, 1999. USEPA. 1999c. Reregistration Eligibility Decision (RED)—EPTC. EPA Report 738-R-99-006. Washington, DC: Office of Prevention, Pesticides and Toxic Substances. December 1999. Available on the Internet at: *http://www.epa.gov/oppsrrd1/REDs/0064red.pdf.* USEPA. 1999d. Reregistration Eligibility Decision
(RED)Facts—O-Ethyl S-phenyl ethylphosphonodithiolate (Fonofos). EPA Report 738-F-99-019. Washington, DC: Office of Prevention, Pesticides and Toxic Substances. November 1999. Available on the Internet at: *http://www.epa.gov/oppsrrd1/REDs/factsheets/0105fact.pdf.* USEPA. 2000a. “Integrated Risk Information Systems (IRIS), 1,3-Dichloropropene.” May 2000. Available on the Internet at: *http://www.epa.gov/iris/subst/0224.htm.* Accessed February 2, 2005. USEPA. 2000b. Unregulated Contaminant Monitoring Regulation for Public Water Systems: Analytical Methods for Perchlorate and Acetochlor; Announcement of Laboratory Approval and Performance Testing
(PT)Program for the Analysis of Perchlorate; Final Rule and Proposed Rule. **Federal Register** . Vol. 65, No. 42. p. 11372, March 2, 2000. USEPA. 2001a. Notice of Opportunity to Provide Additional Information and Comment on Draft Revised Guidelines for Carcinogen Risk Assessment (July 1999), Availability of Draft Revised Guidelines, and Adoption of Draft Revised Guidelines as Interim Guidance. **Federal Register** . Vol. 66, No. 230. p. 59593, November 29, 2001. USEPA. 2001b. Unregulated Contaminant Monitoring Regulation for Public Water Systems; Analytical Methods for List 2 Contaminants; Clarifications to the Unregulated Contaminant Monitoring Regulation. **Federal Register** . Vol. 66, No. 8. p. 2273, January 11, 2001. USEPA. 2001c. Survey of Fertilizers and Related Materials for Perchlorate (ClO <sup>4</sup> ). EPA Report 600-R-01-049. Cincinnati, OH: Office of Research and Development. July 2001. USEPA. 2002a. Announcement of Preliminary Regulatory Determinations for Priority Contaminants on the Drinking Water Contaminant Candidate List. **Federal Register** . Vol. 67, No. 106. p. 38222, June 3, 2002. USEPA. 2002b. The Toxics Release Inventory
(TRI)and Factors to Consider When Using TRI Data. EPA Report 260-F-02-017. November 2002. Available on the Internet at: *http://www.epa.gov/triinter/2002_tri_brochure.pdf* . USEPA. 2003a. Announcement of Regulatory Determinations for Priority Contaminants on the Drinking Water Contaminant Candidate List. **Federal Register** . Vol. 68, No. 138. p. 42898, July 18, 2003. USEPA. 2003b. How are the Toxics Release Inventory Data Used? EPA Report 260-R-002-004. May 2003. Available on the Internet at: *http://www.epa.gov/tri/guide_docs/2003_datausepaper.pdf* . USEPA. 2003c. A summary of general assessment factors for evaluating the quality of scientific and technical information. EPA 100/B-03/001, June 2003. Available on the Web at: *http://www.epa.gov/OSA/spc/pdfs/assess2.pdf.* USEPA. 2004a. Drinking Water Contaminant Candidate List 2; Notice. **Federal Register** . Vol. 69, No. 64. p. 17406, April 2, 2004. USEPA. 2004b. Toxicological Review of Boron and Compounds. EPA Report 635-04-052. June 2004. Available online at: *http://www.epa.gov/iris/toxreviews/0410-tr.pdf.* USEPA. 2004c. “Integrated Risk Information System (IRIS), Boron and Compounds.” August 2004. Available on the Internet at: *http://www.epa.gov/iris/subst/0410.htm.* Accessed February 2, 2005. USEPA. 2004d. Memorandum—TPA (Tetrachloroterephthalic Acid)-Metabolite of DCPA (Dacthal). Evaluation of Potential for Carcinogenicity. Office of Prevention, Pesticide, and Toxic Substances. May 25, 2004. USEPA. 2004e. Memorandum—EFED Review of a Telone Well Monitoring Study. Office of Prevention, Pesticide, and Toxic Substances. March 10, 2004. USEPA. 2004f. Email Communication between James Breithaupt and Wynne Miller regarding the Memorandum—EFED Review of a Telone Well Monitoring Study. September 8, 2004. USEPA. 2004g. State Actions Banning MTBE (State-wide). EPA Report 420-B-04-009. June 2004. Available on the Internet at: *http://www.epa.gov/mtbe/420b04009.pdf.* USEPA. 2005a. Notice—Drinking Water Contaminant Candidate List 2; Final Notice. **Federal Register** . Vol. 70, No. 36. p. 9071, February 24, 2005. USEPA. 2005b. Guidelines for Carcinogen Risk Assessment. EPA Report 630-P-03-001B. March 2005. Available on the Internet at: *http://www.epa.gov/ttn/atw/cancer_guidelines_final_3-25-05.pdf.* USEPA. 2005c. Supplemental Guidance for Assessing Susceptibility to Early-life Exposure to Carcinogens. EPA Report 630-R-03-003F. March 2005. Available on the Internet at: *http://www.epa.gov/ttn/atw/childrens_supplement_final.pdf* . USEPA. 2005d. Application of New Cancer Guidelines. Memorandum from Acting Administrator Stephen L. Johnson. March 29, 2005. USEPA. 2005e. “Integrated Risk Information System (IRIS), Perchlorate and Perchlorate Salts.” February 2005. Available on the Internet at: *http://www.epa.gov/iris/subst/1007.htm.* Accessed February 2, 2005. USEPA. 2005f. Notice—DCPA; Order to Amend to Terminate Uses. **Federal Register** . Vol. 70, No. 143. p. 43408, July 27, 2005. USEPA. 2005g. Unregulated Contaminant Monitoring Regulation
(UCMR)for Public Water Systems Revisions. Proposed Rule. **Federal Register** . Vol. 70, No. 161. p. 49093, August 22, 2005. USEPA. 2006a. Regulatory Determinations Support Document for Selected Contaminants from the Second Drinking Water Contaminant Candidate List (CCL 2). EPA Report 815-D-06-007. Draft. December 2006. USEPA. 2006b. The Analysis of Occurrence Data from the First Unregulated Contaminant Monitoring Regulation (UCMR 1) in Support of Regulatory Determinations for the Second Drinking Water Contaminant Candidate List. EPA Report 815-D-06-007. Draft. December 2006. USEPA. 2006c. The Analysis of Occurrence Data from the Unregulated Contaminant Monitoring
(UCM)Program and National Inorganics and Radionuclides Survey
(NIRS)in Support of Regulatory Determinations for the Second Drinking Water Contaminant Candidate List. EPA Report 815-D-06-009. Draft. December 2006. USEPA. 2006d. “TRI Explorer: Trends—Boron.” Last modified June 8, 2005. Available on the Internet at: *http://www.epa.gov/triexplorer/trends.htm.* [Search for boron trichloride and boron trifluoride.] Accessed February 8, 2006. USEPA. 2006e. “TRI Explorer: Trends—1,3-Dichloropropylene.” Last modified June 8, 2005. Available on the internet at: *http://www.epa.gov/triexplorer/trends.htm.* [Search for 1,3-dichloropropylene.] Accessed February 8, 2006. USEPA. 2006f. “TRI Explorer: Trends—2,4-Dinitrotoluene and 2,6-Dinitrotoluene.” Last modified June 8, 2005. Available on the Internet at: *http://www.epa.gov/triexplorer/trends.htm.* [Search for 2,4-dinitrotoluene, 2,6-dinitrotoluene, and dinitrotoluene (mixed isomers).] Accessed February 8, 2006. USEPA. 2006g. “TRI Explorer: Trends—EPTC.” Last modified June 8, 2005. Available on the Internet at: *http://www.epa.gov/triexplorer/trends.htm.* [Search for ethyl dipropylthiocarbamate.] Accessed February 8, 2006. USEPA. 2006h. “TRI Explorer: Trends—Terbacil.” Last modified June 8, 2005. Available on the Internet at: *http://www.epa.gov/triexplorer/trends.htm* . [Search for terbacil.] Accessed February 8, 2006. USEPA. 2006i. “TRI Explorer: Trends—1,1,2,2-Tetrachloroethane.” Last modified June 8, 2005. Available on the Internet at: *http://www.epa.gov/triexplorer/trends.htm.* [Search for 1,1,2,2-tetrachloroethane.] Accessed February 8, 2006. USEPA. 2006j. Health Effects Support Document for Boron. EPA Report 822-R-06-005. December 2006. USEPA. 2006k. Health Effects Support Document for Dacthal Degradates: Tetrachloroterephthalic Acid
(TPA)and Monomethyl Tetrachloroterephthalic Acid (MTP). EPA Report 822-R-06-006. December 2006. USEPA. 2006l. Health Effects Support Document for 1,1-Dichloro-2,2-bis(p-chlorophenyl)ethylene (DDE). EPA Report 822-R-06-0007. December 2006. USEPA. 2006m. Health Effects Support Document for S-Ethyl dipropylthiocarbamate (EPTC). EPA Report 822-R-06-008. December 2006. USEPA. 2006n. Health Effects Support Document for Fonofos. EPA Report 822-R-06-009. December 2006. USEPA. 2006o. Health Effects Support Document for Terbacil. EPA Report 822-R-06-010. December 2006. USEPA. 2006p. Health Effects Support Document for 1,3-Dichloropropene. EPA Report 822-R-06-011. December 2006. USEPA. 2006q. Health Effects Support Document for 1,1,2,2-Tetrachloroethane. EPA Report 822-R-06-012. December 2006. USEPA. 2006r. Health Advisory for 2,4- and 2,6-Dinitrotoluene. EPA Report 822-R-06-017. December 2006. USGS. 2004. “Mineral Commodity Summaries, January 2004—Boron.” January 2004. Available on the Internet at: *http://minerals.usgs.gov/minerals/pubs/commodity/boron/boronmcs04.pdf.* USGS. 2006. “Information Page on Karst Geology.” Last modified December 5, 2005. Available on the Internet at: *http://water.usgs.gov/ogw/karst/* . Accessed February 20, 2006. Valentín-Blasini, L., J.P. Mauldin, D. Maple, and B.C. Blount. 2005. Analysis of Perchlorate in Human Urine Using Ion Chromatography and Electrospray Tandem Mass Spectrometry. Analytical Chemistry. Vol. 77. pp. 2475-2481. Wang, H., A. Eaton, and B. Narloch. 2002. National Assessment of Perchlorate Contamination Occurrence. Denver: AWWA Research Foundation and American Water Works Association. Wazeter, F.X., R.H. Buller, and R.G. Geil. 1964. Ninety-day Feeding Study in the Rat: IRDC No. 125-004. (Unpublished study, as cited in USEPA, 1998e) Wazeter, F.X., R.H. Buller, and R.G. Geil. 1967a. Two-year Feeding Study in the Dog: IRDC No. 125-011. (Unpublished study, as cited in USEPA, 1998e) Wazeter, F.X., R.H. Buller, and R.G. Geil. 1967b. Three-generation Reproduction Study in the Rat: IRDC No. 125-012. (Unpublished study, as cited in USEPA, 1998e) Woodard, M.W., C.L. Leigh, and G. Woodard. 1968. Dyfonate (N-2790) Three-generation Reproduction Study in Rats. (Unpublished study, as cited in USEPA, 1996c) Woodard, M.W., J. Donoso, and J.P. Gray, *et al.* 1969. Dyfonate (N-2790) Safety Evaluation by Dietary Administration to Dogs for 106 Weeks. (Unpublished study, as cited in USEPA, 1988b and USEPA, 1996c) World Health Organization (WHO), 1994. Indicators for Assessing Iodine Deficiency Disorders and Their Control through Salt iodization. WHO/NUT/94.6.Geneva:World Health Organization(WHO)/International Council for the Control of Iodine Deficiency Disorders (Unpublished study, as cited in Blount *et al.* , 2006b) Dated: April 12, 2007. Stephen L. Johnson, Administrator. [FR Doc. E7-7539 Filed 4-30-07; 8:45 am] BILLING CODE 6560-50-P 72 83 Tuesday, May 1, 2007 Rules and Regulations Part IV Environmental Protection Agency 40 CFR Parts 51, 52, 70, and 71 Prevention of Significant Deterioration, Nonattainment New Source Review, and Title V: Treatment of Certain Ethanol Production Facilities Under the “Major Emitting Facility” Definition; Final Rule ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 51, 52, 70, and 71 [EPA-HQ-OAR-2006-0089; FRL-8301-4] RIN-2060-AN77 Prevention of Significant Deterioration, Nonattainment New Source Review, and Title V: Treatment of Certain Ethanol Production Facilities Under the “Major Emitting Facility” Definition AGENCY: Environmental Protection Agency (EPA). ACTION: Final rule. SUMMARY: This final rule finalizes proposed changes made to the definition of “major emitting facility” in the Prevention of Significant Deterioration (PSD), Nonattainment New Source Review
(NSR)and Title V regulations. Two of the regulatory changes proposed addressed the major source threshold for PSD sources. The remaining proposed regulatory changes finalized in this action address when fugitive emissions are counted for purposes of determining whether a source is a major source under the PSD, nonattainment NSR or Title V programs. The proposal solicited comment on whether wet and dry corn milling facilities that produce ethanol for fuel should continue to be considered a part of the chemical process plants source category, and whether other types of facilities that produce ethanol fuel should be considered for exclusion from the definition of chemical process plants. Based on comments received and evaluated, we have included additional changes to this final rule that exclude other facilities that produce ethanol by natural fermentation and are classified in North American Industry Classification System (NAICS) code 325193 or 312140 from the definition of “chemical process plants.” DATES: This final rule is effective on July 2, 2007. ADDRESSES: *Docket.* The EPA has established a docket for this action under Docket ID No. [EPA-HQ-OAR-2006-0089]. All documents in the docket are listed on the *http://www.regulations.gov* Web site. Although listed in the index, some information is not publicly available, *e.g.* , Confidential Business Information or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically through *http://www.regulations.gov* or in hard copy at the Air and Radiation Docket and Information Center, EPA/DC, EPA West Building, Room 3334, 1301 Constitution Ave., NW., Washington, DC. The Air and Radiation Docket and Information Center telephone number is
(202)566-1742. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The Public Reading Room is located in the EPA Headquarters Library, Room Number 3334 in the EPA West Building, located at 1301 Constitution Ave., NW., Washington, DC. The telephone number for the Public Reading Room is
(202)566-1744. Visitors are required to show photographic identification, pass through a metal detector, and sign the EPA visitor log. All visitor materials will be processed through an X-ray machine as well. Visitors will be provided a badge that must be visible at all times. FOR FURTHER INFORMATION CONTACT: Ms. Joanna Swanson, Air Quality Policy Division, (C339-03), Environmental Protection Agency, Research Triangle Park, NC 27711, telephone number:
(919)541-5282; fax number:
(919)541-5509, e-mail address: *swanson.joanna@epa.gov.* SUPPLEMENTARY INFORMATION: The title of this final rule has been changed from the proposed rule title to better reflect the final rule. The proposed rule was entitled “Prevention of Significant Deterioration, Nonattainment New Source Review, and Title V: Treatment of Corn Milling Facilities Under the “Major Emitting Facility” Definition.” The information presented in this preamble is organized as follows: I. General Information A. Does this action apply to me? B. Where can I obtain additional information? II. Background III. Summary of the Final Rule IV. Policy Rationale for Action V. Significant Comments Received on the Proposal A. What comments did we receive on our proposed changes to the “major emitting facility” definition? B. Why are ethanol production facilities regulated differently under different programs and standards? C. Do we need to make an express section 302(j) finding? D. What are the enforcement implications of these final amendments? E. Are there any environmental and health concerns associated with this final rule? F. Will there be a Federal ethanol-specific VOC emissions test protocol? G. Are there backsliding issues related to this rulemaking? VI. Effective Date of This Rule and Requirements for State or Tribal Implementation Plans and Title V VII. Statutory and Executive Order Reviews A. Executive Order 12866—Regulatory Planning and Review B. Paperwork Reduction Act C. Regulatory Flexibility Analysis D. Unfunded Mandates Reform Act E. Executive Order 13132—Federalism F. Executive Order 13175—Consultation and Coordination with Indian Tribal Governments G. Executive Order 13045—Protection of Children from Environmental Health Risks and Safety Risks H. Executive Order 13211—Actions Concerning Regulations that Significantly Affect Energy Supply, Distribution or Use I. National Technology Transfer and Advancement Act J. Executive Order 12898—Federal Actions to Address Environmental Justice in Minority Populations and Low-income Populations K. Congressional Review Act VIII. Judicial Review I. General Information A. Does this action apply to me? Entities affected by this final rule are facilities that produce ethanol by a natural fermentation process that are classified under NAICS codes 325193 and 312140; and State/local/Tribal governments. Categories and entities potentially affected by this action are expected to include: Industry group SIC a NAICS b Wet Corn Milling 2046 311221 Industrial Organic Chemicals (Ethyl Alcohol) 2869 325193 Sugar Cane Mills 2061 311311 Sugar Beet Manufacturing 2063 311313 Distilleries 2085 312140 State/local/Tribal government 9511 924110 a Standard Industrial Classification. b North American Industry Classification System. B. Where can I obtain additional information? In addition to being available in the docket, an electronic copy of this preamble and final amendments will also be available on the World Wide Web. Following signature by the EPA Administrator, a copy of this notice will be posted on the EPA's NSR Web site, under Regulations & Standards, at *http://www.epa.gov/nsr.* II. Background These regulatory changes affect the applicability provisions of two separate permitting programs: the major NSR program and the title V programs. The NSR program legislated by Congress in parts C and D of Title I of the Clean Air Act
(CAA)is a preconstruction review and permitting program applicable to major stationary sources (major sources) that construct or undertake major modifications. In areas not meeting health-based national ambient air quality standards (NAAQS) and in ozone transport regions (OTR), the program is implemented under the requirements of part D of title I of the CAA for “nonattainment” NSR. We call this program the major nonattainment NSR program. In areas meeting NAAQS (“attainment” areas) or for which there is insufficient information to determine whether they meet the NAAQS (“unclassifiable” areas), the NSR requirements for the PSD of air quality under part C of title I of the CAA apply. We call this program the Prevention of Significant Deterioration
(PSD)program. Collectively, we refer to both programs as the major NSR program. The NSR regulations are contained in 40 CFR 51.165, 51.166, 52.21, 52.24, and appendix S of part 51. Title V of the CAA required EPA to promulgate regulations governing the establishment of operating permit programs. The current regulations are codified at 40 CFR parts 70 and 71. The CAA, as implemented by our regulations, defines the applicability of these different programs based, in part, on whether a stationary source is “major.” For purposes of implementing the PSD program, Congress defined the term “major emitting facility” in section 169(l) of the CAA. This definition contains a specific list of source categories for which an individual source will be considered a major source if it has the potential to emit 100 tons per year
(tpy)of any pollutant for which the local area is in attainment with the NAAQS. This is referred to as the 100 tpy threshold. For any source not otherwise listed, a 250 tpy threshold applies. For purposes of implementing the nonattainment major NSR program, we do not apply different applicability thresholds based on the type of source category. All sources are subject to a 100 tpy threshold or less depending on the severity of the nonattainment problem. All major sources, as the term is defined for title V purposes, are required to obtain title V operating permits. Sources required to obtain title V permits include those sources subject to PSD and nonattainment NSR. Therefore, title V relies in part on the definition of “major emitting facility” for the PSD program. In addition to the determining which applicability threshold applies to a given source, the determination of whether a source is “major” is also partly dependent on whether the stationary source must count both fugitive and stack emissions in determining whether it exceeds the threshold. Section 302(j) provides that
(j)Except as otherwise expressly provided, the terms “major stationary source” and “major emitting facility” mean any stationary facility or source of air pollutants which directly emits, or has the potential to emit, one hundred tons per year or more of any air pollutant (including any major emitting facility or source of fugitive emission of any pollutant, as determined by rule by the Administrator). In 1980, we established a list of source categories that must consider fugitive emissions in source applicability determinations. We used the section 169(1) list of categories in developing our 302(j) list of categories. This final rule involves changes to the “major stationary source” and “major source” definitions in the NSR and title V programs as this definition relates specifically to the manufacturing of ethanol through natural fermentation processes. These changes affect both the applicability threshold and whether this industry must count fugitive emissions in determining its major source status. On March 9, 2006 (71 FR 12240), we proposed to reinterpret the component term “chemical process plants” within the statutory definition of “major emitting facility” in section 169(1) of the CAA to exclude wet and dry corn milling facilities which produce ethanol fuel (Option 1). We requested comment on another option in which we would continue to include wet and dry corn milling facilities that produce ethanol fuel within the definition of “chemical process plants.” (Option 2). We also proposed similarly to reinterpret the regulatory term “chemical process plants” on the list of source categories for which fugitive emissions must be included in determining whether the source is a “major stationary source.” To implement these proposed changes, we proposed to revise the definition of “major stationary source” under 40 CFR parts 51 and 52, and the definition of “major source” under 40 CFR parts 70 and 71. (See 71 FR 12240, March 9, 2006). Finally, we also requested information on other types of ethanol production facilities and comment on whether other types of facilities including those that produce potable ethanol or ethanol fuel should be considered for exclusion from the “chemical process plants” definitions. III. Summary of the Final Rule This rule finalizes Option 1 and reinterpret the component term “chemical process plants” within the statutory definition of “major emitting facility” and regulatory definitions of “major stationary source” and “major source” to exclude wet and dry corn milling facilities that produce ethanol for fuel or ethanol for food. Moreover, based on comments we received, we are extending the exclusion to all facilities that produce ethanol through a natural fermentation process that involves the use of such things as corn, sugar beets, sugar cane or cellulosic biomass as a feedstock regardless of whether the ethanol is produced for human consumption, fuel or for an industrial purpose. This includes denatured alcohol, nonpotable ethanol, nonpotable grain alcohol, potable ethyl alcohol and grain alcohol beverages. We are also reinterpreting the term “chemical process plants” on the list of source categories that must count fugitives emissions in determining whether a source is a major source to be consistent with the way we now interpret that term for purposes of determining the major source threshold. As proposed, we are changing the PSD and nonattainment NSR regulations that we are amending with this action to include amendments to 40 CFR 51.165, 51.166, 52.21, and appendix S. We are also amending the 40 CFR parts 70 and 71 title V regulations. We are not making changes to 52.24 as proposed because we revised that section. Paragraph
(f)now cross-references the provisions of 40 CFR 51.165 for definitions of terms under 40 CFR 52.24, and paragraph
(h)no longer lists source categories. These final rule amendments define “chemical process plants” under the regulatory definition of “major emitting facility” to exclude ethanol manufacturing facilities that produce ethanol by natural fermentation processes. In addition, we have changed our approach to defining the sources within the exclusion as explained below. As explained in the preamble to the proposed rule (71 FR at 12243), in 1981, when we originally interpreted the “chemical process plants” term by guidance, we did so in reference to SIC 28. Since the time we defined the chemical process plant based solely on reference to SIC 28, the Federal Government replaced the SIC code manual with the NAICS. Under the NAICS, as compared to the SIC system, there are over 350 more industries classified. Federal Government agencies have adopted the NAICS to collect statistics from industry establishments more relevant to this economy. The NAICS gives special attention to emerging industries (such as ethanol production) and similar production processes are grouped together. The SIC system, which was last revised in 1987 does not include many of the industries included in the NAICS. Ethanol fuel and industrial ethanol fall within NAICS 325193 (Ethyl Alcohol Manufacturing) which includes denatured alcohol, nonpotable ethanol, and nonpotable grain alcohol. The NAICS 312140 (Distilleries) includes potable ethyl alcohol and grain alcohol beverages. Even though NAICS 325193 (ethyl alcohol manufacturing) has been classified under NAICS' Chemical Manufacturing subsector, unlike under the SIC classification of 2869 (Industrial Organic Chemicals, Not Elsewhere Classified), ethyl alcohol manufacturing is within its own narrowly defined category. The Agency has considered whether, and in what way, we might transition from use of the SIC to the NAICS for purposes of determining the scope of a stationary source in general and for other purposes such as source category determinations. We have not reached any universal conclusions. Notably, however, some commenters expressed concern that by refining the “chemical process plants” definition such that we no longer rely solely on SIC code 28, we would be embroiling the Agency in the “fine grain” analysis we sought to avoid under our initial guidance, negating the objectivity of the current approach. In view of this comment, we think it useful to consider the NAICS codes as a potential tool to address the commenters' concerns. At proposal, we did not use SIC codes to define the facilities that are subject to these changes. We have decided to use NAICS codes to define these facilities in the final rule because the narrow classification of the NAICS codes for ethyl alcohol manufacturing (NAICS code 325193) and distilleries (NAICS code 312140) under the NAICS is useful and eliminates the problem of having to do a “fine grain” analysis. Accordingly, in response to commenters, our final rule references the NAICS codes 325193 and 312140 to exclude facilities using a natural fermentation process to produce ethanol from the definition of “chemical process plants.” We believe that by defining the “chemical process plants” in this way, we retain the objectivity and ease of implementation inherent in our original guidance. The remaining regulatory changes address when fugitive emissions are counted for purposes of determining whether a source is a major source under the PSD, nonattainment NSR, or title V programs. Our final rule treats the term “chemical process plants” in those regulations in the same manner as we treat it for purposes of determining the major source threshold. IV. Policy Rationale for Action In our proposed rule, we expressed several reasons to support our proposal to change the definition of “chemical process plants.” First, we cited concerns related to the disparate treatment of ethanol fuel production verses production of ethanol intended for human consumption by applying two different major source thresholds. Because the two manufacturing processes are substantially similar, we believed that the process should be treated identically for purposes of the PSD and title V regulations regardless of the intended product. We also cited concerns that continuing to regulate the ethanol fuel industry, under the 100 tpy major source threshold, regardless of the production method could stymie the growth of the industry, and hamper our nation's efforts toward energy independence. Some commenters agreed with our general approach. Other commenters asserted that a mere similarity in processes did not justify our proposed redefinition of the “chemical process plant” category. Other commenters questioned whether permitting agencies treated the two types of ethanol production differently for regulatory purposes. After reviewing the comments, we re-examined whether our policy concerns remain valid, and affirm our conclusion that a change in the “chemical process plant” category definition is warranted. Although we received conflicting information as to how permitting authorities regulate ethanol intended for human consumption, especially at plants that also produce ethanol for fuel, we maintain the fundamental premise for our proposal, that ethanol, regardless of intended use, is produced through substantially similar processes, and that similar processes should be regulated in a similar way. Although there may be jurisdictional differences in the way these industries are regulated, we believe this further supports the need to clarify the definition of “chemical process plants” relative to the ethanol production industry as a whole and does not negate the fundamental basis on which we proposed the rule. We continue to believe that supporting our nation's efforts toward energy independence is an important national goal, and that this consideration is appropriate in deciding how to balance our nations economic growth with environmental protection. The Energy Policy Act of 2005 (Pub. L. 109-58) established a renewable fuel standard
(RFS)that requires an increasing use of renewable fuels in our nation. It is clear that continued growth of the ethanol industry will play a vital role in achieving our nation's energy and environmental objectives. While we are uncertain what impact this regulatory action may have on furthering our progress toward the goal of energy independence, we believe that including ethanol fuel in the “chemical process plants” presented potential obstacles for growth in the industry. These obstacles primarily include the time it takes to obtain a preconstruction permit, and, in some cases, the potential costs that may be incurred as a result of having to apply additional emissions controls. As we discuss, in section V, we conclude that this rule is not likely to result in significant net environmental harm. Nonetheless, even if our consideration of potential environmental consequences understates potential negative environmental consequences, we believe that the potential for other environmental benefits and the desire to support our nation's energy policy objectives outweigh any potential negative environmental consequences that could potentially result from this rule. We maintain, as we did in the proposal preamble, that we have the discretion to define “chemical process plants” to exclude wet and dry corn milling facilities. As stated above, we based our proposed rule on the premise that ethanol production should be treated similarly regardless of whether it is produced using either the wet or dry corn milling process, and regardless of whether the end product is used as fuel or for human consumption because the process steps involved are essentially the same. As we noted in the proposal, the only difference is the final step where a small amount of denaturant (such as gasoline) is added to render the ethanol unfit for human consumption. This rationale also supports expansion of the exclusion to all facilities that produce ethanol through a natural fermentation process. We received numerous comments supporting this finding. Although some commenters pointed to differences in the production process, we are not persuaded that the differences justify disparate regulatory treatment. We also received comments justifying the expansion of our regulatory exclusion to other feedstock and end product uses. We discuss our responses to these comments in more detail in section V of this preamble. We did, however, receive a few comments stating that our regulatory approach is fundamentally flawed, because regardless of the similarity of process, ethanol fuel and perhaps ethanol production in general should be regulated under the 100 tpy threshold. Some commenters assert that we are not entitled to deference because such facilities fall within the plain meaning of the term “chemical processing plant.” Others assert that section 169(1) shows Congress’ intent to focus on a facility's finished product and economic sector in which an industry competes. We do not believe that the term “chemical process plant” is subject to a “plain meaning interpretation.” There is not a universally accepted definition of chemical process, and accepted definitions differ depending on whether you view the term from a purely scientific sense or from an engineering sense, or for economic purposes. The scope of the chemical industry is in part shaped by custom rather than by logic and excludes industries that nevertheless engage in chemical processes, *e.g.* , petroleum refineries are a separate category on the section 169(l) list. 1 One definition offered by the commenter is so broad it would encompass nearly every manufacturing activity regardless of source category, and would render other categories on the source category list redundant. The specific chemical process relevant here, natural fermentation, is common to many industries. For example, natural fermentation is used by non-ethanol producing food manufacturers which Congress chose not to subject to the 100 tpy. We find no “plain meaning” definition of “chemical process plant” that can be applied in light of these facts. Accordingly, we do not believe that whether or not an industry engages in a “chemical process” and specifically whether it engages in “natural fermentation” can be used as the decisive factor in determining whether Congress intended the industry to be included within the “chemical process plants” category. 1 Chemical reaction. (2007). In *Encyclopedia Britannica* . Retrieved April 5, 2007, from Encyclopedia Britannica. Online: *http//www.britannica.com/eb/article9110109* ; Chemical industry. (2007). In *Encyclopedia Britannica* . Retrieved April 5, 2007, from Encyclopedia Britannica. Online: *http//www.britannica.com/eb/article9108378* . We also disagree that section 169 clearly shows Congress's intent on what factors we must consider in making source category determinations. As discussed below, we have used a variety of considerations in making source category determinations. We generally have not conducted economic analysis in making these decisions, nor have we based our decision solely on the end product produced or strictly followed an SIC approach for all categories. V. Significant Comments Received on the Proposal Significant comments received on, and our responses to, the proposed amendments to the “major emitting facility” definition are presented in the following paragraphs. A. What comments did we receive on our proposed changes to the “major emitting facility” definition? The **Federal Register** proposal preamble notes that most ethanol is produced in the U.S. from sugar or starch-based feedstock using two basic processes: The dry mill process and the wet mill process. The preamble stated that wet milling operations are specifically addressed under SIC Code 2046 (“Wet Corn Milling”) under Major Group 20 (“Food and Kindred Products”). Wet corn milling units engaged in producing food products are subject to the 250 tpy threshold under PSD. The proposal provided that
(1)Both wet and dry corn milling processes can produce ethyl alcohol for human consumption,
(2)the processes are identical to those which produce ethyl alcohol for fuel (with some exceptions), and
(3)industry stakeholders believe that the thresholds should be the same. Based on these reasons, we proposed to redefine “chemical process plants” under the definition of “major emitting facility” found in section 169(l) of the CAA to exclude wet and dry corn milling facilities that produce ethanol for fuel (Option 1). Several commenters on the proposal argued that there was insufficient explanation as to why we proposed the change for only one type of facility ( *i.e.* , corn milling facilities). Some of these commenters provided that we should extend the proposed exclusion to cellulosic biomass, sugar beets, and/or sugar cane facilities that produce ethanol fuel. A few commenters supported equal treatment of corn milling facilities regardless of the ethanol end product ( *i.e.* , for human consumption, ethanol fuel, industrial ethanol). The Corn Refiners Association
(CRA)suggested that we expand the exclusion to all fermentation processes that result in products other than ethanol (in addition to ethanol) that replace petroleum feedstocks or are used to make food products ( *e.g.* , citric acid made from corn, propylene glycol made from corn), however, expanding to products other than ethanol is not within the scope of this rulemaking as it was not discussed at proposal. This final rule finalizes the exclusion for wet and dry corn milling ethanol production facilities and expands that exclusion to include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 and 312140 (includes denatured alcohol, nonpotable ethanol, nonpotable grain alcohol, potable ethyl alcohol, and grain alcohol beverages). 2 2 North American Industry Classification System. United States, 2002. Expanded Edition with Added “Bridges.” Executive Office of the President. Office of Management and Budget. Pgs. 235-236, and pg. 313. The following subparagraphs present greater detail on the comments received on the proposed “major emitting facility” definition and whether the “chemical process plants” exclusion for corn milling ethanol fuel production facilities should be expanded to facilities that produce ethanol fuel from cellulosic biomass, sugar beets, and sugar cane; and facilities that produce industrial ethanol from corn, cellulosic biomass, sugar beets, and sugar cane. 1. Proposed Treatment of Corn Milling Facilities Under the “Major Emitting Facility” Definition *Comments:* One commenter asserted that the EPA, when applying section 169(1), needs to discern whether a facility's primary activity is a type listed as a 100 tpy “major” source in section 169(1)—in this case, whether a facility's primary activity is a chemical production process. Another indicated that our established policy requires that EPA look at the primary product produced and that we have not explained our change in policy. *Response:* While this rule represents a change in our definition of “chemical process plants”, it does not represent a change in our general approach to determining the scope of source categories. In our proposed rule, we pointed to our August 7, 1980 rulemaking wherein we indicated that we would use the 2-digit “Major Group” listings as defined by the SIC manual of 1972 (as amended in 1977) for purposes of determining the scope of the source. In subsequent guidance, we clarified that we did not necessarily intend to follow the 1980 preamble approach for defining the scope of the source when determining the applicable major source threshold once the source is defined. 3 3 *See e.g.* Memo. Edwin B. Erickson, Regional Administrator, to George Clemon Freeman, Counsel for Reserve Coal Proportion Company, July 06, 1996; and Memo. *Request for PSD Applicability Determination* , Golden Aluminum Company, San Antonio, TX, from William B. Hathaway, Director Air, Toxics and Pesticides Division to Steve Spraw, Deputy Executive Director, Texas Air Control Board, July 28, 1989. Importantly, contrary to some commenters' assertions, EPA explicitly rejected the use of the “primary activity test” as the decisive means of defining source categories listed under section 169(1). *Id.* As the proposal preamble explains, the SIC manual was not designed for regulatory application, but was developed primarily for the collection of economic statistics and for the consistent comparison of economic data between various sectors of the U.S. economy. The use of SIC codes by the EPA is not required by the CAA, nor was it referenced in any legislative history related to section 169(1) of the CAA. While it may be appropriate for economic statistical purposes to place certain types of sources in the same or in different categories, EPA never intended the SIC code to be the decisive factor for determining whether a given stationary source should be regulated as a listed source category. As one commenter properly pointed out, we use the SIC code manual only as the starting point for determining which pollutant-emitting activities should be considered as part of the same source category, but rely on case-by-case assessments to determine whether a particular stationary source belongs in a given source category. (Docket No. EPA-OAR-HQ-2006-0089-0086). 4 4 See Memo. *Treatment of Aluminum Die Casting Operations for the Purposes of New Source Review Applicability* , from Thomas C. Curran, Director Information Transfer and Program Integration Division, to Director, Office of Ecosystem Protection, Region I, *et.al.* , December 4, 1998, and Memo. *Applicability of Prevention of Significant Deterioration
(PSD)and New Source Performance Standards
(NSPS)to the Cleveland Electric Incorporated* , Plant in Willioughby, Ohio, May 26, 1992. Using this case-by-case approach, we applied different rationales for determining if a particular stationary source falls in a given source category. For example, we relied on the existing NSPS definition of municipal waste combustor in determining whether a source falls within a listed category. *Id.* We have also generally stated that we believe that Congress intended that we consider the source's pollutant-emitting activity in determining whether a source is within a listed source category rather than the source's finished product. In some cases, the listed source category does not directly correspond to a specific SIC code, and we considered the type of feedstock, the process steps, and end products produced to determine whether a given stationary source was part of the source category. 5 5 See Memo. *Treatment of Aluminum Die Casting Operations for the Purposes of New Source Review Applicability* , from Thomas C. Curran, Director Information Transfer and Program Integration Division, to Director, Office of Ecosystem Protection, Region I, *et. al.* , December 4, 1998. For the chemical process plant category, EPA took a much more straightforward approach. Instead of specifically considering the pollutant emitting activity, the feedstocks, process steps, end products, or application of existing NSPS definition to making case-by-case determinations, EPA chose to specifically define the category based on SIC 28. We based this decision on a desire to promote consistency with source scope determinations, and for ease of implementation and objectivity. 6 Notably, however, in that same memorandum we stated that we have the ability to amend the definition of chemical process plant to add to or delete from the scope of the source category, especially in light of the inconsistent treatment of the alcohol fuel and beverage alcohol processes, but declined to do so at that time. With this action, we are acting in light of that continuing discretion and the facts before us now. 6 See Memo. *Classification of the Bardstown Fuel Alcohol Company under PSD* , from Edward E. Reich, Director Division of Stationary Source Enforcement, to Thomas W. Devine, Director Air and Hazardous Materials Division, Region IV, August 21, 1981. *Comment:* Several commenters assert that EPA places too much reliance on Congress' use of the report submitted by Research Corporation of New England (“Research Corp. report”) and the fact that ethanol production was not specifically addressed in the report. Commenters assert that Congress' silence can not be taken as an intent to exclude ethanol from the “chemical process plants” definition. One commenter believes, that the mere fact that chemical processes occur and that toxic chemicals are added is enough to conclude that Congress would intend to regulate the industry as a chemical process plant. A commenter also stated that Congress used broad terms like “chemical processing plants” precisely to capture new ways of making products and to avoid having to change the statute in the future to capture these activities. *Response:* As noted in the proposal preamble and repeated here, section 111 of the CAA requires the Administrator of EPA to establish Federal standards of performance for new stationary sources which may significantly contribute to air pollution and was intended by Congress to complement the other air quality management approaches authorized by the 1970 CAA. After enactment of section 111, EPA hired Research Corporation of New England (Research Corp.) to study stationary sources of air pollution in order to establish priorities for developing and promulgating NSPS. Because of limited resources, EPA could not feasibly set NSPS requirements for all categories of stationary sources simultaneously. Therefore, the goal of the Research Corp. study was to identify sources for which NSPS controls would have the greatest impact on reducing the quantity of atmospheric emissions. Research Corp. examined approximately 190 different types of stationary sources that potentially could be determined to be major emitting facilities, and provided information on the types of air pollutants that those sources emitted. The Research Corp. study was used by EPA in setting priorities for the order in which it would promulgate NSPS requirements for categories of stationary sources. The Research Corp. study was also relied on by Congress in identifying the 28 categories of stationary sources specifically listed in the definition of the term “major emitting facility” in section 169(1) of the CAA. 122 Cong. Rec. 24,520-23 (1976). As explained by Senator McClure in the Congressional Record, the EPA Administrator examined the data from the draft Research Corp. study and determined that 19 of the stationary source categories examined should initially be classified as major emitting facilities. Senator McClure further explained that the Senate Committee added nine more categories of stationary sources to the 19 selected by EPA for a total of 28 source categories. 122 Cong. Rec. at 24,521.2 As discussed in the proposal preamble, in discussing the specific sources identified in section 169(1), Senator McClure stated: Mr. President, I ask unanimous consent that an extract from that report of the Research Corp. of New England, listing the 190 types of sources, from which the EPA took 19, and the committee took 28, be printed in the Record at this point as an illustration of what the committee examined and the kinds of sources the committee intended to include and exclude, recognizing that it is neither exclusive nor invariable. There is administrative discretion to add to the list, to change the list. But the committee spoke very clearly on its intent on that question. 122 Cong. Rec. at 24,521 (1976). As a result of Senator McClure's action, the table from the draft Research Corp. report containing the list of 190 types of sources was printed in the Congressional Record. The approximately 190 source categories identified in Research Corporation's report were further classified into ten general groups for purposes of the study—stationary combustion sources, chemical processing industries, food and agricultural industries, mineral products industries, metallurgical industries, and miscellaneous sources (evaporation losses, petroleum industry, wood products industry, and assembly plants). For the chemical process industry grouping, the Research Corp. study considered 24 different source categories and their associated pollutants. Notably, within the chemical process industry listings in the 1977 final report and in the 1976 draft report (as incorporated into the Congressional Record) there is no listing which refers to ethanol production, ethanol fuel production, or corn milling operations. Given this history, we agree with commenters that Congress' silence on the matter can not be taken as an intent to exclude ethanol, nor however, do we believe that the silence can be taken as an intent to include ethanol within the chemical process plant definition. It is precisely because Congress did not express an intent, and because the Congressional record shows that Congress recognized that the list was neither “exclusive or inclusive” that we believe we have discretion to determine whether or not the ethanol industry belongs in the chemical process plants source category. We are not persuaded that the mere fact that chemical reactions occur or that toxic chemical are added would have compelled Congress to include the industry within the category. These factors are too broad and too common in a multitude of industries to be effective criteria for categorizing sources. *Comment:* We received many comments supporting our position that basic steps of both processes are similar for both wet and dry corn milling. One commenter explained that a plant may produce beverage, industrial, and ethanol fuel at the same plant using the same equipment. Conversely, one commenter provided that the production of ethanol for fuel involves processes that are different in character than production of ethanol for human consumption, involving more steps and additional distillation that is necessary, among other things, to produce 100% ethanol (200 proof) needed for use as a fuel. This commenter pointed out that the closer the distillation process gets to producing 100% ethanol, the more energy/fuel is consumed, the more steps required, and the more pollutants emitted from the chemical processing plant. One commenter explained that while the two processes are theoretically the same, ethanol fuel is produced on a much larger scale, and competes with other fuel markets. They provided that alcohol for human consumption does not contain as much alcohol as ethanol fuel after the distillation process (40-50% compared to 90-100% ethanol), and is subject to different regulations ( *e.g.* , health, food safety). The commenters also asserted that the use of a molecular sieve in ethanol fuel production distinguishes this production from human alcohol consumption. Finally, one commenter asked EPA to explain in greater detail its conclusion that the two processes are the same. One commenter stated that ethanol fuel production facilities are more like refineries than an alcohol for consumption facility. They argued that ethanol fuel production facilities should be regulated similarly to a chemical process plant as that is what they are producing. *Response:* In the U.S., ethanol (ethyl alcohol) is currently being produced either synthetically or through the fermentation of sugars derived from agricultural feedstocks. For ethanol produced synthetically, either ethylene or hydrogen (H <sup>2</sup> ) and carbon monoxide
(CO)are used as the feedstock. As of 2002, only two facilities in the U.S. were producing synthetic ethanol. 7 The majority of ethanol produced in the U.S. is produced from sugar or starch-based feedstock ( *e.g.* , corn, millet, beverage waste) using two basic processes: the dry mill process and the wet mill process. The key difference between these two processes is the initial treatment of the grain. In the wet mill process, the grain is soaked and then ground to remove germ, fiber, and gluten from the starch prior to cooking. 7 Memorandum from Mary Lalley, Eastern Research Group, Inc., to Bob Rosensteel. Ethanol Production Industry. U.S. EPA, July 2, 2002. See Docket No. EPA-HQ-OAR-2006-0089-0009. In the dry mill process, the grain or feedstock is not separated into its constituent parts prior to cooking. Both wet and dry milling operations produce ethanol as well as other coproducts. “Co-products from the dry mill process, separated from the ethanol in the distillation step, include distiller's dried grain
(DDG)and solubles (S), which are often combined and referred to as DDGS. DDGS is used as an animal feed. In the wet mill process, co-products are separated from the ethanol production process in the initial grinding or milling step. Coproducts from the wet milling process include fiber and gluten, which are used for animal feed and corn oil.” 8 8 Memorandum from Mary Lalley, Eastern Research Group, Inc., to Bob Rosensteel. Ethanol Production Industry. U.S. EPA, July 2, 2002. See Docket No. EPA-HQ-OAR-2006-0089-0009. Most new ethanol production capacity comes from dry mill processing facilities. Wet milling operations, on the other hand, can produce ethanol, including ethanol for fuel, but are typically primarily engaged in producing starch, syrup, oil, sugar, and by-products, such as gluten feed and meal. For ethanol which will be used as fuel, toxic solvents (typically gasoline) are added to the ethanol to render it unfit for human consumption (denatured). This additional step is required to develop ethanol fuel regardless of whether the dry or wet mill process was employed to develop the initially potable ethanol. We recognize that though the corn milling ethanol production processes for ethanol fuel and ethanol for human consumption are theoretically the same, ethanol fuel is produced on a much larger scale, and competes with other fuel markets. We also acknowledge that alcohol for human consumption does not typically contain as much alcohol as ethanol fuel (or some other denatured ethanol products ( *e.g.* , denatured ethanol products made for industrial use) after the distillation process (40-95% for distilled spirits), and is subject to different regulations ( *e.g.* , health, food safety). This does not negate the fact that the natural fermentation and distillation processes (though the number of distillation steps and length of fermentation may vary) up until the time the denaturant is added for ethanol fuel (or other denatured ethanol products) are similar. We are not persuaded that these differences are significant or that they warrant different treatment under PSD. Given that the basic goal of PSD are to ensure that economic growth will occur in harmony with the preservation of existing clean air resources, that other regulations in place ensure equivalent or near equivalent BACT level of control will continue, and that a State's minor NSR program will apply when major NSR/PSD does not apply, we believe that the basic goal of PSD will be maintained. 2. Expansion to Other Ethanol Production Processes *Comments: Supports Expansion to Other Feedstock.* Two commenters requested that the proposed preferred option (Option 1) be expanded to include facilities that produce ethanol fuel from molasses. One commenter noted that there are facilities other than corn milling which are capable of producing ethanol, notably molasses processing plants, and they should also be excluded from the definition of “major source” under the PSD, NSR, and title V programs. They provided that processes for both the production of ethanol from sugarcane molasses and from corn are similar, and because the processes are similar, the air emissions from the production of either product would also be similar. One commenter stated that EPA's proposed rulemaking specifically requested public comments with respect to how future technological developments in the ethanol industry may be affected by the proposed rulemaking. They explained that while the current ethanol industry is dominated by the wet and dry corn milling process, the future of the ethanol industry could involve additional grain feedstocks such as wheat, barely, or rice as well as cellulosic feedstock's such as wood waste, switchgrass, and municipal solid waste. This commenter provided that they believed since EPA's proposal is rather narrowly focused on wet and dry corn milling newer ethanol production technologies currently under development could fall into the same regulatory quandary EPA is trying to correct through their proposal. They recommended that EPA's final rulemaking be expanded to also cover the other ethanol production technologies that may be developed in the future. They suggested that the EPA modify the currently proposed rule language to adopt language more consistent with the various NSPS rules (such as the synthetic organic chemical manufacturing industry (SOCMI) wastewater NSPS Subpart YYY standard) and exclude any process that uses “natural fermentation” to produce ethanol from the definition of a “chemical processing plant” under section 169. One commenter stated that they believed that it is appropriate to treat all other types of facilities which produce ethanol from cellulosic biomass feed stocks similarly to how corn milling facilities are being proposed to be treated under Option 1. One State commenter provided that other environmental rules have made distinctions with regard to applicability between ethanol by fermentation/biological processes and synthetic ethanol production: 1. NSPS subparts NNN and RRR—excludes ethanol by fermentation. The commenter stated that EPA has previously determined that ethanol-manufacturing facilities may be exempt from NSPS subparts RRR and NNN on a case-by-case basis. The commenter explained that in this instance, the ethanol facilities in question use a biological process to ferment the converted starches in corn into ethanol. These NSPS subparts did not envision unit operations for biological processes. 2. Categorical waste water effluent limits for Organic Chemicals, Plastics and Synthetic Fibers, part 414—excludes ethanol by fermentation. The provisions of this part do not apply to any process wastewater discharges from the manufacture of organic chemical compounds solely by extraction from plant and animal raw materials or by fermentation processes. The commenter argued that EPA's proposal of Option 1 would be consistent with the above programs and that the exclusion should not be limited to “corn” wet and dry milling to make ethanol fuel. They supported their position by stating that several plants currently use milo along with corn to make ethanol fuel, and that the future of ethanol appears to be in the use of biomass, *i.e.* , cellulosic material. They explained that the only difference would be that the feedstock is a biomass material other than corn; and that fermentation and distillation processes would be essentially unchanged. They asserted that if the rule is not expanded to exclude cellulosic material, there could be a negative impact on the growth of cellulosic ethanol. This commenter argued that this could have an unintended complication as the energy balance favors ethanol from cellulosic feed stock over ethanol by corn. One commenter stated that it should not matter what biomass or carbohydrate feedstock is used in the ethanol production process as the natural fermentation and distillation steps would be the same as they are for corn milling ethanol production. One commenter provided that chemical feed stocks made from renewable sources should all be excluded as many of the products subject to the definition of chemical process plant were originally synthetically produced when SIC codes were established ( *e.g.* citric acid and propylene glycol made from corn). Opposes Expansion to Other Feedstock One commenter opposed any suggestion to exclude “other types of facilities which produce ethanol fuel, such as those using cellulosic biomass feedstocks, *e.g.* , solid waste, agricultural wastes, wood, and grasses * * * from the chemical process plants definition due to having production processes similar to those found at wet and dry milling facilities in cases where potable ethanol or ethanol fuel is being produced,” or for any other reason. They provided that while they believed that the use of ethanol (especially cellulosic ethanol) as a transportation fuel has significant potential environmental benefits, the high cost of natural gas had recently caused a shift from the use of natural gas to coal for process heat which they believed would lead to an erosion of the carbon benefits of displacing petroleum-based fuels. *Response:* In the proposal preamble, we solicited comment on whether other types of facilities that produce ethanol fuel, such as those using cellulosic feedstocks, *e.g.* , solid waste, agricultural wastes, wood, and grasses, should also be considered for exclusion from the chemical process plants definition due to having similar processes to those found at wet and dry milling facilities in cases where potable ethanol or ethanol fuels is being produced. We requested information, including process flow diagrams, on the processes that would be used to develop ethanol using other feedstock. Process diagrams were provided that indicated that although the processes to produce sugars from these feedstocks differ, similar fermentation and distillation processes in the production of ethanol fuel from cellulosic material would be employed. Commenters also provided process diagrams illustrating similar processes in the production of ethanol from molasses (which is used as a feedstock in the production of rum). As with cellulosic feedstocks, the breakdown of these feedstocks to produce sugars may differ, but the ethanol fermentation and distillation processes were similar. In molasses (using both sugar beets and sugar cane feedstock) ethanol production, the molasses is diluted with water, acidified to precipitate minerals and then decanted to produce the mash. Yeast and nutrients are added to the mash and fermentation converts the sugars in the molasses to alcohol. There, fermented mash is then distilled to separate and concentrate the ethanol. The ethanol is dehydrated and, if being used to produce fuel alcohol, denatured. There are currently no U.S plant producing ethanol from sugar feedstocks (sugar beets, sugar cane) therefore there is little data available on their feasibility as an ethanol feedstock, however, Brazil and several other countries are producing ethanol from these feedstocks. In cellulosic ethanol production, acid is introduced to the feedstock at high temperatures to release hemicellulose sugars (depending on the type of cellulose used). If acids are toxic, they are removed prior to saccarification (break down of starches) and fermentation steps. Enzymatic hydrolysis to produce sugars from cellulose is another alternative being researched in pilot and demonstration commercial plants. The result is a “beer” with 4 to 5 percent alcohol content by weight. The distillation step is employed to produce ethanol at about 92 to 93 percent alcohol which must be processed by a vapor-molecular sieve (to further dehydrate the ethanol) to create fuel (the last step involving the adding of a denaturant). It is important to note that the use of a molecular sieve is not unique to cellulosic biomass ethanol production facilities as it is something that is used at many corn milling ethanol production facilities. Molecular sieves have become a popular means to dehydrate ethanol as they are low cost, environmentally friendly, and require less energy. Facilities that use molecular sieves replace azeotropic distillation systems that use cyclohexane or benzene (HAP), which were expensive, costly to operate, and energy intensive. 9 There is currently no commercial cellulosic ethanol production plant operating in the U.S., however, there are several existing pilot plants, and several commercial plants are in the planning stages. 9 BBI International. INNOVATIONS in Dry-Mill Ethanol Production. Based on the process diagrams and information received from commenters that indicate that the fermentation and distillation processes are similar (included as part of the technical record), even though the pre-steps and after-steps may differ, we are expanding the exclusion of the definition of “major emitting facilities” to include ethanol production facilities that produce ethanol through natural fermentation processes included in NAICS codes 325193 or 312140. We are not excluding other chemicals ( *e.g.* , citric acid and propylene glycol made from corn) made from renewable sources with this final rule. The scope of this rule is ethanol production and processes and there was no solicitation, or sufficient basis provided, to support expansion of exclusion to other chemicals. B. Why are ethanol production facilities regulated differently under different programs and standards? Several commenters provided input on the historic regulatory treatment of wet and dry corn milling facilities which produce ethanol fuel. Some of the commenters stated that EPA's proposal to exclude wet and dry corn milling facilities from the definition of “chemical process plants” was consistent with historic regulatory treatment, while others argued that it was inconsistent with historic regulatory treatment. *Comments:* The following comments were received on the historic and current regulatory treatment of wet and dry corn milling facilities that produce ethanol fuel. • One commenter requested clarification of rule applicability, with regards to ethanol production, of numerous NSPS and MACT standards. • Two industry commenters suggested that the rule include changes to the relevant NSPS under 40 CFR part 60 since alcohol production facilities are potentially subject to several standards of performance for new stationary sources, including 40 CFR part 60, subparts Kb (volatile organic liquids storage vessels), VV (equipment leaks of volatile organic compounds
(VOC)in the SOCMI), NNN (SOCMI distillation operations), and RRR (VOC emissions from SOCMI reactor processes. • Two State commenters provided examples where wet and dry corn milling facilities which produce ethanol fuel are treated as chemical process plants (40 CFR part 60, subparts VV, NNN, RRR (in Minnesota); 40 CFR part 63, subpart FFFF Miscellaneous Organic NESHAP (the MON Rule); AP-42 (Chapter 9.9.7 for Corn Wet Milling)). • Two environmental consultants, two industry commenters, and one State noted that EPA rulemakings and associated interpretive guidance have either established exemptions (or allow sources to seek exemptions on a case-by-case basis) for chemicals produced through fermentation (as with corn milling ethanol production) from various SOCMI industry regulations, including the NSPS subparts RRR (SOCMI process reactors) and YYY (SOCMI wastewater units). • One State commenter stated that categorical wastewater effluent limits for Organic Chemicals, Plastics, and Synthetic Fibers found in 40 CFR part 414 (promulgated under the Clean Water Act) excludes ethanol manufacturing by fermentation. • Two industry commenters were concerned that the 27th listed source category in the NSR and title V programs also regulates ethanol plants as a result of the NSPSs captured under this source category. • One environmental commenter stated that EPA has treated “ethanol blending facilities”—facilities that mix ethanol into gasoline—as refineries. 40 CFR 80.2(u). (“Ethanol blending plant means any refinery at which gasoline is produced solely through the addition of ethanol to gasoline, and at which the quality or quantity of gasoline is not altered in any other manner.”) (emphasis added). Additionally, the commenter argued that EPA has referenced the distinction between “chemical grade” ethanol that is used in transportation fuel and other kinds of ethanol. See 40 CFR 79.55(e)(1)-(2). *Response:* The applicability of differing rules is standard-specific and determinations were made under individual rulemakings and will not be changed under this rulemaking. There is no directive for the applicability to be the same across CAA programs and standards and applicability determinations need to be determined on a case-by-case, or standard-by-standard, basis. For example, ethanol is listed as a SOCMI chemical for which 40 CFR part 60, subpart YYY (SOCMI wastewater units) applies, however, the supplemental proposed rule (63 FR 67988; September 12, 1994) excludes certain processes from the definition of chemical process unit
(CPU)because they were not considered SOCMI processes, but are sometimes associated with SOCMI processes. Organic chemicals extracted from natural sources or totally produced from biological synthesis such as pinene and beverage alcohol were specifically excluded from the CPU definition. Under 40 CFR part 60, subpart YYY, the determination for excluding biological processes was based on the designation for the process unit, in contrast to the plant site. Under the 40 CFR part 63, subpart FFFF (the Miscellaneous Organic National Emission Standards for Hazardous Air Pollutants (NESHAP) (the MON)) standards, the applicable miscellaneous organic chemical process unit for which standards apply includes all equipment that collectively function to produce a product or material described in the standard (including denatured alcohol). The pollutant to be controlled ( *e.g.* , HAP, VOC, particulate matter (PM)), processes to be controlled, available control technologies, timing of standard development, and program and standard directives drive the applicability of individual standards. As for the commenters' concern that the 27th listed source category in the NSR and title V programs regulates ethanol plants as a result of the NSPSs captured under this source category, this concern would not be valid as all of the NSPSs listed by the commenters (40 CFR part 60, subparts Kb, VV, NNN, and RRR) were proposed and promulgated after August 7, 1980. The 27th listed source category referenced by the commenters includes “[a]ny other stationary source category which, as of August 7, 1980, is being regulated under section 111 or 112 of the CAA.” C. Do we need to make an express section 302(j) finding? As noted in the proposal preamble, when we promulgated the list of source categories relative to the definition of “major emitting facility” in the NSR regulations on August 7, 1980 (45 FR 52676), we adopted this same list to identify source categories for which fugitive emissions were to be counted in determining whether a source was a major source. We promulgated the 28 source categories as a result of the decision in *Alabama Power* v. *Costle* , 626 F. 2d. 323 (D.C. Cir. 1979). In *Alabama Power* , the court held that “fugitive emissions are to be included in determining whether a source or modification is major only if and when EPA issues an appropriate legislative rule.” The proposed rule Option 1 was to change the definition of chemical process plants with the definition of major stationary source and major source and would correspondingly also change our interpretation of that term relative to the 302(j) source category list. At proposal we stated that since we were not changing the list of source categories in the regulations, a section 302(j) finding was unnecessary. Some commenters on the rule disagreed with EPA's position, and stated that EPA needs to make an express section 302(j) finding in order to redefine when fugitive emissions are counted. *Comments:* Several commenters opposed EPA's proposal to de-list corn-based ethanol fuel production from the list of facilities identified by EPA, pursuant to CAA section 302(j). One commenter stated that the EPA can not avoid making the necessary determinations to list a facility or source pursuant to section 302(j) by merely listing categories and later determining which sources and facilities to include in the category. The commenter asserts that, in 1980, the EPA determined that “chemical process plants,” as defined in the SIC Manual, which specifically includes ethanol production plants, are a type of source category for which fugitive emissions should be counted. The commenter stated that EPA made this determination, based on its finding that these sources could degrade air quality significantly, and that the costs of listing this category were not unreasonable compared to the benefits. The commenter provided that the CAA does not allow EPA to identify generic categories that include unspecified sources. The commenter argued that EPA's proposal violates the CAA and EPA's own prior interpretation of the CAA. Another commenter stated that the EPA must specifically evaluate whether eliminating this requirement is appropriate based on criteria that relate to the intent of the PSD program and the air quality impact of such emissions. The commenter explained that the EPA has adopted criteria for the very purpose of determining whether to consider fugitive emissions—those criteria require EPA to examine
(1)Whether sources in the category could degrade air quality; and
(2)whether the cost of controlling fugitives are unreasonable compared to the expected benefits. The commenter argued that it would be arbitrary and irrational for EPA to affirmatively change its treatment of these sources without subjecting that decision to a meaningful substantive evaluation. The commenter asserts that because the initial classification imputed a need to address fugitive emissions from these plants, and because nothing in EPA's proposal functions to counter that expectation, the commenter believes that it was not rational for EPA to exclude ethanol fuel plants from the fugitive emissions requirements without conducting an appropriate assessment. *Response:* As we stated in the proposal, we are not changing the list of categories that we developed by rule under section 302(j). We are merely reinterpreting what is included within the definition of one of those categories. When EPA added chemical processing plants to the section 302(j) list in 1980, it did so based on a very general finding that sources within the category could degrade air quality and did not make any specific determination as to the appropriateness of counting fugitive emissions from any particular source types that may fall within the category. Thus, we do not think that interpreting the category to exclude a narrow set of facilities triggers the section 302(j) rulemaking requirement that applies when categories are added to the list. Nonetheless, even if this action triggers the section 302(j) rulemaking requirement, we believe this rulemaking constitutes a sufficient section 302(j) rule that is consistent with the way we interpreted that requirement in 1980 and re-affirmed in 1984. (45 FR 52676, 52690 (Aug. 7, 1980) and 49 FR 43202 (Oct. 28, 1984)). Specifically, we determined that our action to list a category under section 302(j) may be based on a policy decision after considering certain criteria, that we do not need extensive technical analysis to support our determination, and that the purpose of rulemaking is to afford the public an opportunity to comment on the Administrator's decision. In 1979, when we initially proposed to use the section 169(1) source category list, our stated rationale for the proposal was only that we decided to focus first on the listed sources because of our experience in quantifying the “fugitive emissions” from these sources. (44 FR 51924, 51931 (Sept. 5, 1979)). Similar to comments received on this proposed rule, we received comments then that our rulemaking then was inadequate, and that we should have conducted technical analysis to support our proposed rule. We rejected commenters assertions. We also stated that the purpose of the rulemaking was to afford the public the opportunity to comment on the Administrator's decision, and to allow commenters to present factual or policy arguments that it would not be appropriate to include fugitive emissions in threshold calculations. *Id.* In our 1980 final rule, we stated that our decision to use the section 169(1) source category list was “a matter of policy.” We reiterated our position that we had greater experience in quantifying fugitive emissions from sources on the section 169(1) source category list; and, we observed that those sources have traditionally been considered the major polluters in the country. Despite the limited nature of the technical support for our proposal, we concluded that we conducted an adequate section 302(j) rulemaking since the affected sources were afforded an opportunity to comment on our policy decision. (45 FR at 52690-92). In 1984, after re-examining our interpretation of the section 302(j) requirements, we affirmed that the rulemaking requirements of section 302(j) were intended to afford the public an opportunity to comment on the Administrator's decision to list a category, and that we were not required to undertake extensive technical analysis to support our determination. That 1984 preamble discussion addressed two criteria relevant to the Administrator's decision to require sources to include fugitive emissions in threshold applicability determinations. We note that commenters mischaracterized the manner in which the two criteria operate. The final rule stated that [a] determination by EPA that the sources in a category pose a threat of significant air quality degradation in effect establishes a presumption that the sources should be subject to PSD and nonattainment review * * *. Commenters then may seek to rebut this presumption by producing a record that unreasonable social or economic costs relative to the anticipated benefits would occur if PSD or nonattainment review were applied to a particular category of sources * * * (49 FR at 43203-08). Importantly, we discussed these criteria in light of our overall belief that listing a category involved the Agency's exercise of policy discretion for which we carry a very low analytical burden in deciding to list a source category. Under this interpretation, section 302(j) functions as a useful “safety valve,” while at the same time minimizing the expenditure of Agency resources. 49 FR 43202, 43208 (October 26, 1984). Notably, the 1984 final rule preamble did not address how or whether that requirement applies to EPA's decision to interpret a category already on the list to exclude a narrow set of sources. Consistent with the “safety valve” purpose served by a section 302(j) rulemaking, we believe that it is not necessary to require a negative finding with respect to the same criteria before we interpret a category on the list to exclude certain types of sources. In sum, having made a policy decision based on a limited technical finding, we do not believe that our technical burden now in acting to refine a category on the list, should be greater than the technical analyzes we undertook in listing the categories in the first instance. Notably, as we stated, when EPA added “chemical processing plants” to the section 302(j) list in 1980, it did so based on a very general finding that sources within the category could were considered major polluters. We did not make any specific determination as to the appropriateness of counting fugitive emissions from any particular type of stationary sources within that category. At the time we conducted the section 302(j) rulemaking, few ethanol facilities existed and inclusion of ethanol manufacturers was not specifically analyzed in our section 302(j) rule. When we examined the issue more closely in 1981, we made a policy decision without conducting technical analysis, to include ethanol fuel manufacturing within the chemical processing plant category. We based this decision on a desire to maintain consistency with use of SIC 28 and ease of implementation. Thus, before now, we considered this industry to be a source within the listed category. However, we find that the category should not include these sources or others who engage in natural fermentation process to produce ethanol. We believe that it is not necessary to require a negative finding with respect to the criteria that apply to list a category under section 302(j) before we interpret a category on the list to exclude certain types of sources. We believe that the economic and policy rational for the exclusion of certain ethanol production facilities from the chemical processing plant category for purposes of defining major emitting facility that we present elsewhere in the preamble to the proposed rule and in this preamble also provides ample support for a section 302(j) determination not to count fugitive emissions from such facilities. This decision is precisely the kind of “flexibility to provide industry-by-industry consideration and appropriate tailoring of coverage” envisioned by the *Alabama Power* Court ( *Alabama Power Co.* v. *Costle* , 636 F. 2d 323, 369 (D.C. Cir. 1979). Having been afforded the opportunity to comment on the Administrator's decision, commenters failed to present compelling factual or policy arguments based on specific information which show that our policy decision is inappropriate. Accordingly, we have satisfied the section 302(j) rulemaking requirement. D. What are the enforcement implications of these final amendments? *Comments:* One commenter asserted that the new rule would represent a drastic about-face in Federal environmental policy, and could trigger revoking of consent decrees, refunds of fines, and removal of pollution control equipment. The commenter explained that in the last four years, Department of Justice
(DOJ)and EPA attorneys have consistently argued, in at least nineteen separate Federal court complaints, that ethanol plants, including those with product lines of both fuel and beverage ethanol, are chemical manufacturing facilities under section 169(1) of the CAA, 42 U.S.C. 7479 (1). Specifically, this commenter indicated that the Federal government has argued in some of these complaints that ethanol production plants are facilities for synthetic organic chemical manufacturing and are affected facilities under part 60, subpart VV, 40 CFR 60.480, and are subject to the leak detection and monitoring requirements on 40 CFR 60.482-1 through 60-489, which govern the synthetic organic chemical manufacturing industry. The commenter stated that the EPA formally charged that ethanol fuel facilities were chemical plants in 2002, when the EPA and the State of Minnesota filed complaints against all 12 Minnesota ethanol plants. Those complaints stated that the plants were major emitting sources under section 169
(1)of the CAA, 42 U.S.C. 7479 (1). Those cases were settled when these plants agreed to install thermal oxidizers and other additional pollution control equipment on their plants to bring their emissions per criteria pollutant to below 100 tpy. The companies were also fined from $18-42,000 a piece. A companion complaint was also filed, and settled, against Ace Ethanol in Wisconsin. The commenter expressed that the DOJ stated in a December, 2005 press release that 83% of the ethanol industry is under consent decrees. The decrees were all imposed to enforce the PSD provisions of the CAA under the legal theory that the ethanol plants were synthetic organic chemical manufacturing plants. All of these consent decrees required the plants to keep their emissions of each criteria pollutant below 100 tpy. Some decrees also required compliance with the leak detection and monitoring requirements found at 40 CFR 60.482-1 through 60-489, which govern the synthetic organic chemical manufacturing industry. In sum, the commenter stated that DOJ and EPA have consistently stated in court documents on nineteen separate occasions over the last 4 and one-half years that ethanol plants are chemical manufacturing plants. The commenter further stated that the DOJ and EPA have committed countless thousands of hours of staff and attorney time, laboring to advance this position. The commenter argued that the proposed preferred Option 1 could produce a situation where some or all of these companies, especially those who have been charged within the last several months (Cargill, MGP, Golden Triangle, AGP, and others) could claim that the consent decree terms, such as the 100 tpy limit per pollutant, no longer applies to their plants. Any plant who has not had their consent decree discharged could immediately apply to have the decree dissolved since the decrees' emissions limits no longer apply to ethanol plants. Additionally, the commenter asserts that these companies could ask the EPA to pay them back the millions in fines that they paid. The commenter is concerned that under Option 1, companies would be entitled to remove their thermal oxidizers when their current permits expire. One commenter representing State and local governments opposed the EPA's preferred option (Option 1). They argued that if new facilities are allowed to construct without controls options, then EPA may face future lawsuits from existing facilities, insisting on a level playing field, for removal or relaxation of their control strategies. The commenter expressed that the EPA should uphold their previous decisions to enforce installation of pollution control technologies at all ethanol facilities. *Response:* This rule should have no effect on the existing consent decrees and the obligations of the sources to implement the consent decrees. The consent decrees are binding legal documents. The provisions of the consent decrees, by their terms, do not allow a source to alter its consent decree obligations as specified therein. Any civil penalties that had been due and owing to the United States have been paid into the United States Treasury. Even if the United States were so inclined, refunds of civil penalties from the United States Treasury would be unprecedented. The conditions for termination of the consent decrees are specified expressly in each consent decree. Such consent decrees can only be terminated after the source completes its consent decree obligation and demonstrates compliance with the consent decree terms to the satisfaction of the United States. One of those terms is that a source obtains a Federally-enforceable operating permit incorporating the terms of the consent decree. Our rationale for this final rule is explained in detail elsewhere in the preamble to the final rule. That we took actions to enforce the requirements in place before this rule does not undermine the basis for this rule. Existing facilities located in attainment areas would be required to maintain their existing permit limits and other permit requirements unless and until revised through a permitting procedure which, to be consistent with CAA section 110(a)(2)(C) and 40 CFR 51.160, must be shown not to cause or contribute to a violation of the NAAQS. We believe that raising the threshold from 100 tpy to 250 tpy in attainment areas will likely encourage facility expansions and construction of larger, more economically efficient plants, which in turn, will emit less emissions per gallon of ethanol produced. The 100 tpy threhold on the other hand encourages the construction of more numerous, less economically efficient smaller facilities. In addition, as noted below, the environmental and health impacts of this rule are limited. E. Are there any environmental and health concerns associated with this final rule? Several comments were received concerning the potential negative impacts to the environment based on our proposed change. Some of the significant comments and concerns are provided in the following paragraphs. *Comment:* Several commenters expressed that increasing the PSD threshold for ethanol production facilities from 100 tpy to 250 tpy could lead to emissions increases that would not occur in absence of this rulemaking. *Response:* 1. Introduction We acknowledge that there may be some emissions increases as a result of this rulemaking. Over the past 25 years, domestic ethanol fuel production has steadily increased due to changing environmental regulation, Federal and State tax incentives, and market demand, including an increasing number of State ethanol mandates, the phase out of MBTE, and elevated crude oil prices. In order to meet current and future demand, new facilities may be constructed or existing facilities may need to be expanded. However, we do not expect many new facilities to be constructed (other than those already planned) in the short-term ( *e.g.* , over the next 5 years). As noted later, we predict that the revision of the major source threshold applicable to the ethanol fuel industry will allow for the construction of larger, more economically efficient plants which, in turn, will emit less emissions per gallon of ethanol produced. Comments submitted on the proposal concurred with that prediction. (See Docket Nos. EPA-HQ-OAR-2006-0089-0086, 0039, 0040, 0045, 0046, 0050, 0057, 0058, 0062, 0063, 0065, 0066, 0067, 0068, 0069, 0072, 0073, 0075, 0076, 0077, 0078, 0079, 0085, 0090, 0091, 0092, 0093, 0094, 0098, 0100, 0101, 0102, 0103, 0104, 0105, 0107, 0108, 0110, 0111, 0112, 0113, 0114, 0115, 0116). There are an estimated 114 facilities that currently exist in the U.S. that produce ethanol by natural fermentation as of March, 2007. Of these, an estimated 7 of the facilities are planning expansions. Eighty additional ethanol production facilities are currently under construction. Existing ethanol production capacity is estimated at 5,600 million gallons year (mgy). New construction and expansions will add an estimated 6,400 mgy to existing capacity. The estimated total capacity (inclusive of expansions and new constructions) will be about 12,000 mgy (12 billion gallons year (bgy)) once expansions and new constructions are completed. 10 10 Ethanol Biorefinery Locations; U.S. Fuel Ethanol Industry Biorefineries and Production Capacity; updated March 13, 2007. Commenters expressed concern that this rule would result in emissions increases because
(1)The rule increases the PSD major source threshold from 100 tpy to 250 tpy for the subject ethanol production facilities (new or existing facilities) in attainment areas; and
(2)that, for new sources, fugitive emissions will no longer be included in calculations to determine whether a source is a major PSD source in attainment areas or to determine nonattainment NSR applicability. Section 2 of this response section discusses our consideration of the potential for emissions increases due to the increased threshold, section 3 discusses our consideration of the potential for emissions increases due to facilities no longer needing to count fugitives when determining whether they are a major source, and section 4 presents our overall conclusions. 2. Increase in Major Source Threshold *Emissions data.* One industry commenter provided estimates indicating that a controlled 110 mgy ethanol production facility could be assumed to emit 100 tpy and that a controlled 250 mgy ethanol production facility could be assumed to emit 250 tpy. 11 The commenter reported that emissions from both of these facilities are based on conservative potential to emit estimates, presenting worst-case operating scenario emissions and that actual plants generally emit less than their potential to emit estimates. As noted later, we believe future economies of scale will potentially drive the expansion and construction of facilities with capacities equal to or greater than 250 mgy with actual emissions being less than 250 tpy. Thus, under this scenario, production of ethanol would result in less emissions per gallon produced than today. 11 ICM, Inc., Air Dispersion Modeling Study. 100 TPY vs. 250 TPY. April 28, 2006. Attachment 3. (EPA-HQ-OAR-2006-0089-0086, Attachment 3). Volatile organic compounds
(VOC)emissions occur from the cooling system baghouses, dryers, CO <sup>2</sup> fermentation scrubbers, equipment leaks, transfer, and storage vessels. Estimates provided include estimates for emissions of nitrogen oxides that result from fuel combustion in the thermal oxidizers and dryers. The potential to emit estimates assume that 100% of the NO <sup>X</sup> emissions are emitted in the form of NO <sup>2</sup> to depict a worst-case scenario. Carbon monoxide
(CO)emissions are also attributed to fuel combustion at the thermal oxidizers and dryers. As such, CO emissions were also included in their potential to emit estimates. Emissions of particulate matter less than 10 microns (PM <sup>10</sup> ) result from grain unloading and loading, grain handling and milling, natural gas combustion and process operations such as dryers and cooling towers, as well as from truck traffic and haul roads. As noted, particulate emissions are generated by grain receiving, milling and distillers dried grains and solubles
(DDGS)loading. Most of these emissions are controlled by baghouses. Haul road emissions are generally dependent on the amount of vehicle miles traveled on the roads (more miles traveled equate to higher emissions). Grain fugitives are assumed to be controlled by a choked flow system, which reportedly is the typical control for fugitive particulate emissions. Carbon monoxide and VOC emissions are typically the largest source of emissions from these facilities and are the likely pollutants that would trigger major PSD/NSR review. 12 Based on this, we have focused our analysis on increases in CO and/or VOC emissions that could potentially occur as a result of increased production and this rulemaking. We acknowledge that emissions increases in NO <sup>X</sup> and PM <sup>10</sup> could also occur concurrent with CO and/or VOC emissions increases, but these pollutants are not as relevant to the major source determinations for ethanol plants. Additionally, we note that since ozone generation is dependent on the mixing of VOCs and oxidized nitrogen in the presence of sunlight, control of VOCs in NO <sup>X</sup> -limited environments may not be the best solution for reducing ground-level ozone emissions in those environments. Addressing other pollutants may result in greater environmental benefits. 12 ICM, Inc., Air Dispersion Modeling Study. 100 TPY vs. 250 TPY. April 28, 2006. Attachment 3. (EPA-HQ-OAR-2006-0089-0086, Attachment 3). *Attainment areas.* There are an estimated 171 denatured ethanol production facilities located or are planned to be located in attainment areas. If we assume that a 110 mgy ethanol production facility can be controlled under a 100 tpy threshold (for VOC and CO) including fugitives, it then can be assumed that facilities that have capacities less than or equal to 110 mgy are either controlled as synthetic minors or are uncontrolled facilities that have emissions that fall below the 100 tpy emissions threshold (for VOC and CO). Additionally, given that a 250 mgy ethanol production facility can be controlled under a 250 tpy threshold (for VOC and CO), including fugitives, it then can be assumed that facilities that have capacities greater than 250 mgy are currently regulated as major sources. Several commenters have provided that there are many ethanol production facilities that take on BACT controls in order to be permitted as “synthetic minor” sources or are subject to controls or PTE restrictions that may be similar to BACT controls because of other existing regulations ( *e.g.* , NSPSs, NESHAP, State regulations). (See Docket Nos. EPA-HQ-OAR-2006-0089-0086, 0057, 0074). We do not have sufficient information to discern the number of facilities that are synthetic minor. However, those facilities which must comply with NSPS, NESHAP or State regulations will continue to be subject to those regulations as those requirements are unaffected by this rule change. In addition, we do know that there are approximately 6 facilities located in attainment areas that have low production capacities (less than 6 mgy). The emissions from these facilities would likely fall below both a 100 tpy and 250 tpy threshold and ethanol production is likely a secondary process at the facility ( *e.g.* , ESE Alcohol, Inc. in Leoti, KS has an ethanol production capacity of 1.5 mgy from seed corn; Land O' Lakes of Melrose, MN has an ethanol production capacity of 2.6 mgy from cheese whey). For the purposes of this analysis, we assume that these small production capacity facilities will not be affected by this rulemaking. Based on this rulemaking, existing facilities located in attainment areas would be required to maintain their existing permit limits and other permit requirements unless and until revised through a permitting procedure which, to be consistent with CAA section 110(a)(2)(C) and 40 CFR 51.160, must be shown not to cause or contribute to a violation of the NAAQS. In addition, any expansion would also have to comply with any applicable NSPS, NESHAP, or State regulation. Most of the existing ethanol production facilities in attainment areas have current production capacities less than 110 mgy and would, therefore, likely be either synthetic minor or actual minor source facilities, with a few facilities likely being permitted as major PSD sources. Given a worst-case scenario, the maximum these facilities could emit as a result of a change or modification and solely by the threshold being increased to 250 tpy is 249 tpy (up to the major source threshold). New facilities located in attainment areas would be subject to a 250 tpy major source applicability threshold when determining major source applicability. Therefore, these new facilities would be allowed to emit up to 249 tpy (and produce up to 250 mgy) VOC and/or CO as minor sources as a result of the major source threshold being increased from 100 tpy to 250 tpy. Although other factors may influence the construction of new ethanol production facilities in the future, we do not expect many additional facilities to be constructed over the next 5 years as a result of this rule. Over the past 25 years, domestic ethanol fuel production has steadily increased due to changing environmental regulation, Federal and State tax incentives, and market demand, including an increasing number of State ethanol mandates, the phase out of MBTE, and elevated crude oil prices. We assume, and commenters have supported that, under a 250 tpy threshold, there is incentive to construct more efficient facilities with larger capacities. (EPA-HQ-OAR-2006-0089-0086). Therefore, in the future, economies of scale will potentially drive the expansion and construction of facilities with capacities equal to or greater than 250 mgy with actual emissions being less than 250 tpy. Thus, under this scenario, production of ethanol would result in less emissions per gallon of ethanol produced today. *Nonattainment areas.* There are an estimated 23 ethanol production facilities located in or planned to be located in ozone nonattainment areas (12% of all facilities). 13 In nonattainment areas, existing ethanol production facilities will continue to be subject to the 100 tpy threshold, therefore, there will not be emissions increases as a direct result of this rulemaking associated with increasing the major source threshold in attainment areas for these existing sources. 13 Memorandum to Docket EPA-HQ-OAR-2006-0089. Spreadsheet Presenting Ethanol Production Facility Locations and Ozone Nonattainment Designations. April 2007. 3. Impact of Not Counting Fugitives in Emissions Applicability Calculations *Emissions data.* For fugitive emissions, we used the potential to emit emissions estimates provided by a commenter when considering the potential VOC and CO fugitive emissions from the 110 mgy and 250 mgy model plants. 14 Based on these estimates, an estimated 16% of plant VOC and/or CO emissions from the 110 mgy production plant are fugitives, and 13% of plant VOC and CO emissions from the 250 mgy production plant are fugitives. 15 14 ICM., Air Dispersion Model Study. 100 TPY vs. 250 TPY. April 28, 2006, Attachment 3. (EPA-HQ-OAR-2006-0089-0086). 15 ICM, Inc., Air Dispersion Modeling Study. 100 TPY vs. 250 TPY. April 28, 2006. Attachment 3. (EPA-HQ-OAR-2006-0089-0086, Attachment 3). *Attainment areas.* Existing facilities subject to a PSD permit will need to continue to include their fugitive emissions, as permitted, in attainment areas. This is because existing permit limits and other permit requirements remain in effect and enforceable unless and until revised through a permitting procedure which, at a minimum, 16 to be consistent with CAA section 110(a)(2)(C) and 40 CFR 51.160, must be shown not to cause or contribute to a violation of the NAAQS and to comply with all applicable requirements. When determining whether an emissions increase is significant, these sources would still be required to count their fugitives. 16 Ability to change treatment of fugitives in individual PSD permits may be limited by the terms of such permits. New facilities located in attainment areas would be subject to a 250 tpy major source applicability threshold and would no longer need to count fugitives when determining major source applicability. Therefore, these new facilities would be allowed to emit up to an additional 33 tpy (and produce up to 250 mgy) VOC and/or CO (assuming VOC and/or CO fugitives account for 13% of facility wide VOC and/or CO emissions) as minor sources as a result of this rulemaking. As we noted previously, we do not expect many new facilities to be constructed over the next 5 years. However, provided that there is construction of more facilities over the next 5 years, such a facility would be able to emit 33 tpy more VOC and/or CO emissions (assuming 13% of 250 tpy are fugitive emissions no longer required to be included in the major source applicability calculations) than it would have prior to this rulemaking. *Nonattainment areas.* As noted in the introduction, there are concerns that emissions may increase in nonattainment areas because fugitive emissions will no longer be required to be included in calculations to determine nonattainment NSR applicability. As noted previously, in nonattainment areas, both existing and new ethanol production facilities will continue to be subject to the 100 tpy threshold. Conservatively, approximately 23 of the 194 facilities (approximately 12 percent) are located in ozone nonattainment areas. 17 17 Memorandum to Docket EPA-HQ-2006-0089. Spreadsheet Presenting Ethanol Production Facility Locations and Ozone Nonattainment Designations. April 2007. Of the estimated facilities located in ozone nonattainment areas, 4 of the facilities have reported capacities below 6 mgy. These types of facilities produce ethanol from waste beverages, waste beer, and/or cheese whey and more than likely produce ethanol secondary to other processes at the facility ( *e.g.* , the Golden Cheese Company of California has a reported ethanol production capacity of 5 mgy). As with the small production capacity facilities mentioned previously that are located in attainment areas, we do not believe that these facilities will be affected by this rulemaking. Existing facilities subject to a nonattainment NSR permit will need to continue to include their fugitive emissions, as permitted, in nonattainment areas. This is because existing permit limits and other permit requirements remain in effect and enforceable unless and until revised through a permitting procedure which, to be consistent with CAA section 110(a)(2)(C) and 40 CFR 51.160, must be shown not to cause or contribute to a violation of the NAAQS and to comply with all applicable requirements. When determining whether an emissions increase is significant, these sources would still be required to count their fugitives. 18 18 Where a stationary source is adding a emissions unit or modifying an existing emissions unit, the State's SIP-approved minor NSR program that permits physical modifications of existing minor sources would govern. We believe that very few ethanol production facility constructions in nonattainment areas will occur in the near future and that future facilities (as with existing facilities) will likely be located near an applicable feedstock (such as corn). Currently, and in the near foreseeable future, corn is the primary feedstock used in ethanol production in this country and the bulk of the corn grown in this country is located in attainment areas, and transportation costs may influence decision makers to locate such plants close to the feedstock. In the future, where cellulosic materials will be used as a feedstock for ethanol production on a commercial scale, agricultural and other waste may be used. We believe that this rulemaking, which increases the PSD major source threshold to 250 tpy, will provide decision makers with additional incentives to locate these facilities in attainment areas. However, if a new facility did locate in a nonattainment area to meet future demand for ethanol, it is assumed that it would be a 110 mgy facility that would have the potential to emit an additional 16 tpy of VOC and/or CO fugitive emissions. It is important to note that most, if not all, ethanol fuel plants employ an active leak detection and repair
(LDAR)program to minimize VOC emissions from tanks, valves, pumps and piping. (Docket No. EPA-HQ-OAR-2006-0089-0074). Fugitive particulate emissions from vehicular traffic are often controlled by a combination of paving and cleaning plant roads and other dust suppression methods. (Docket No. EPA-HQ-OAR-2006-0089-0074). Based on the assumption that there will be few, if any, facilities that will expand or be constructed in nonattainment areas in the future, and in light of the fugitive control measures that are employed at these facilities, we do not believe that this rulemaking will result in significant emissions increases in nonattainment areas. 4. Our Overall Conclusion As stated previously, we believe that a larger, more economically efficient plant that is able to produce more ethanol fuel could result in significantly more fuel production without a corresponding increase in energy use or pollutant emissions, thereby resulting in a net reduction of environmental impacts as compared to the greater number of smaller, less efficient ethanol fuel production facilities that would be needed to achieve the same level of production. Given the likelihood of larger capacity facilities being better able to reduce emissions per gallon of ethanol produced than a greater number of smaller facilities, it is more logical to increase the capacity at a larger facility than locating additional smaller capacity facilities in an area. Similarly, it is more logical to allow the construction of larger capacity facilities in an area than locating numerous smaller capacity facilities in an area. In conclusion, the effect of this rule is limited given that other emissions requirements continue to apply and will be unaffected by this rulemaking. As we have noted in our discussion, VOC and/or CO emissions (and other increases in emissions for NO <sup>X</sup> and PM <sup>10</sup> ) will likely occur. However, other Federal regulations that apply will continue to apply to ethanol production facilities including numerous NSPS ( *e.g.* , 40 CFR part 60, subparts Db, Dc (boilers and steam generating units); DD (grain handling and storage facilities); VV (leaks from VOC equipment); K, Ka, and Kb (storage vessels), and NESHAP ( *e.g.* , 40 CFR part 63, subparts FFFF (miscellaneous organics. New Source Performance Standards require the application of the best demonstrated system of emission reductions for affected facilities to control criteria pollutants and NESHAP require the application of maximum achievable control technology to control HAP. We also note that nothing in this rule precludes a permitting authority from choosing to retain the 100 tpy major source threshold, as necessary, to meet its air quality needs. In short, we weighed and considered the environmental consequences of this rule relative to the expected benefits of ethanol use. The increased use of renewable fuels such as ethanol and biodiesel are expected to reduce dependence on foreign sources of petroleum, increase domestic sources of energy, and help transition to alternatives to petroleum in the transportation sector. *Comment:* A couple of commenters stated that there will be an increased use of coal over natural gas to fuel the ethanol production process due to the higher cost of natural gas and the increased threshold. One commenter stated that many of the new ethanol fuel plants (which tend to be significantly larger than ethanol for human consumption plants) are considering using coal as a source of energy for the chemical processing instead of natural gas as the industry has traditionally used. The commenter expressed that the use of coal for production of ethanol fuel will result in much greater emissions of conventional pollutants such as NO <sup>X</sup> , SO <sup>2</sup> , and PM, as well as increases in toxic pollutants, such as mercury that are not expressly regulated by the PSD program. They also argued that the use of coal will result in increases in CO <sup>2</sup> emissions from ethanol plants which will threaten to undermine any global warming benefits of using ethanol instead of petroleum-derived fuels. *Response:* We disagree with the assertion that existing ethanol production facilities that currently use natural gas as a fuel supply will likely convert to coal as a result of raising the major source threshold to 250 tpy. One commenter reported, and we agree, that the capital costs of such a conversion would be costly and facilities would more likely opt for increasing their production capacity. (Docket No. EPA-HQ-OAR-2006-0089-0086). The Renewable Fuels Association reports that, to their knowledge, no gas-fired mill has made a conversion to coal [EPA-HQ-OAR-2006-0089-0086]. It is acknowledged, however, that new plants may decide to use coal in lieu of natural gas because of the increased major source emissions threshold and because of it being a cheaper fuel source and that this could result in increases in emissions of pollutants not expressly regulated by the PSD program. However, even if there is an increased use of coal, these facilities will be subject to the same PSD major source limit requirements as facilities that use natural gas, and will continue to be subject to other regulations (State and Federal). We also acknowledge that the use of coal could result in increases in CO <sup>2</sup> emissions from ethanol plants. *Comment:* Several commenters provided specific examples of situations where implementation of our proposed Option could cause or contribute to the negative impact on an area. One State commenter expressed that the proposed Option 1 would result in a negative impact on growth due to the projected increment consumption. They said that although some States could deal with this locally by making their regulations stricter than the Federal regulations, others are restricted because they have rules that limit them from having laws in their States that are stricter than the Federal rules. A commenter representing State and local governments provided that even current minor sources—under the existing 100 tpy threshold, including fugitive emissions—are known to contribute significantly to potential violations of the NAAQS. They stated that permit data from STAPPA and ALAPCO members show that emissions from some ethanol fuel production facilities contribute to an area exceeding the 24-hour PM <sup>10</sup> standard and, in some cases, are close to violating the 24-hour PM <sup>10</sup> increment. Another commenter stated that EPA and North Dakota have not resolved the issue of sulfur dioxide PSD exceedances in Class I areas of North Dakota and Montana, and that if Option 1 is promulgated for ethanol plants, there is potential for an increase of more than double the allowable sulfur dioxide emissions from proposed and existing ethanol plants. *Response:* Generally, although we acknowledge that there may be negative impacts to particular regions or areas due to this rulemaking, we do not think there would be many instances where this is the case. Provided that there are local and regional instances with the potential for unacceptable negative impacts from this rule, a State or local government regulations/minor NSR program can be implemented to mitigate such impacts. In fact, a State is not required to adopt the rule's change in threshold and can maintain the 100 tpy threshold or other lower threshold in order to best serve its air quality/economic needs. If a State's regulations provide that its major source PSD thresholds cannot be more stringent than those prescribed by the Federal programs, its State minor NSR program should be able to address specific local concerns such as some of those suggested by the commenters. We also acknowledge that there are local and Regional concerns that this rule is contrary to the purposes of the PSD program. It is true that one purpose of the PSD program is to ensure that new sources do not cause or contribute to an area that is in attainment becoming a nonattainment area. However, we believe that, in part, this directive will continue to be addressed by a State's minor NSR permit program and various Federal, State and Local air quality requirements. Federal regulations that apply and will continue to apply to ethanol production facilities include numerous NSPS ( *e.g.* , 40 CFR part 60, subparts Db, Dc (boilers and steam generating units); DD (grain handling and storage facilities); VV (leaks from VOC equipment); K, Ka, and Kb (storage vessels), and NESHAP ( *e.g.* , 40 CFR part 63, subparts FFFF (miscellaneous organics. New Source Performance Standards require the application of the best demonstrated system of emission reductions for affected facilities to control criteria pollutants and NESHAP require the application of maximum achievable control technology to control HAP. F. Will there be a Federal ethanol-specific VOC emissions test protocol? *Comments:* A couple of States argued that there is a need for a Federally-approved VOC performance test specifically for ethanol production. Reasons given include that
(1)VOC testing at ethanol plants would be straightforward,
(2)facilities would be assured of equitable treatment between them,
(3)States would be able to more-easily and consistently determine compliance with Federal PSD rules, and
(4)administering the Clean Air permitting programs for ethanol plants would be easier if there were a Federally-approved method to measure volatile organic compound emissions from ethanol plants. *Response:* The EPA believes that the existing Reference Methods found at 40 CFR part 60 are applicable for estimating the total mass emissions of VOCs, as defined in 40 CFR 51.100(s), from each process commonly used at wet and dry corn mills that produce ethanol. Over the past 5 years, VOC emissions from ethanol facilities under consent decrees with the United States have been successfully tested using a combination of EPA Reference Method 25 or 25A, and Reference Method 18. In addition to the currently available Reference Methods, EPA works with industry groups to develop their own test methods as an alternative to using existing EPA Reference Methods, provided that the alternative methods produce accurate results. One example of an alternative method by an industry is the method developed by the Corn Refiners Association for measuring VOC emissions from the wet corn milling industry. This method was developed by the wet corn milling industry specifically to measure VOC mass emissions from processes within their facilities. It is a systematic approach for developing a specific list of target organic compounds and determining the appropriate sampling procedure to collect those target compounds during subsequent VOC emissions testing. This method is currently available on EPA's Emission Measurement Center Web page ( *http://www.epa.gov/ttn/emc/prelim/otm11.pdf* ). The EPA plans to begin a rulemaking in the near term regarding the above-noted new method. If promulgated, this method will be codified in 40 CFR part 51, appendix M, as a Federally-approved method for measuring VOC emissions from wet corn milling plants. G. Are there backsliding issues related to this rulemaking? *Comments:* Several commenters expressed concern that the States would not be able to adopt the proposed changes without violating the antibacksliding provisions under sections 193 of the CAA. The commenter alleges that the PSD program and “synthetic minor” limits are control requirements. Another commenter stated that states will have to comply with the anti-backsliding provisions of section 116 before adopting these changes. Finally, the same commenter noted that EPA's justification for the final rule appears inconsistent because we did not discuss the impacts of the proposed rule on state efforts to attain and maintain compliance with the NAAQS, as States will be required to do to adopt the changes under State law. *Response:* Section 193 applies to nonattainment areas only. It provides that “no control requirement in effect, or required to be adopted by an order, settlement agreement, or plan in effect before the date of the enactment of the CAA of 1990 may be changed unless the change insures equivalent or greater emission reductions of such air pollutant.” We have previously stated our position that section 193 is ambiguous as to whether it applies to the NSR program, and that although we have chosen a conservative approach in our review of NSR SIP changes, our past option to review changes for consistency with section 193 is not conclusive of its scope. See 70 FR 39420, 69 FR 31056, 31063. Recently, the U.S. Court of Appeals for the D.C. Circuit ruled on our interpretation of a similar, but not identical term “controls” as used in section 172(e), and found that “NSR is a control.” *South Coast Air Quality Mgmt. Dist.* v. *EPA* , 472 F.3d 882, 901 (D.C. Cir. 2006). We respectfully disagree with the court's finding on this issue and have filed a petition for rehearing of the decision. We also believe that the Court's interpretation of the term “controls” in section 172(e) is not necessarily decisive of how we should interpret the similar but different term “control requirement” in section 193, although we recognize we will need to take into account the D.C. Circuit's decision following the outcome of our rehearing request. Nonetheless, this action does not in and of itself modify any requirements applicable to nonattainment areas. We believe the appropriate time to determine the applicability of and compliance with section 193 is when a control requirement in a nonattainment area is changed. For States that undertake a SIP revision, we will address the applicability of section 193 in our future actions to approve the SIP revisions. To the extent States can implement this approach consistent with their existing SIPs, the SIP requirements are not changing, and section 193 does not apply. Similarly, we disagree with commenters that state that existing sources would simply be able to lift existing permit limits upon promulgation of this rule. These existing permit limits and other permit requirements remain in effect and enforceable unless and until revised through a permitting procedure which, to be consistent with CAA section 110(a)(2)(C) and 40 CFR 51.160, must be shown not to cause or contribute to a violation of the NAAQS and to comply with all applicable requirements. 19 19 Where a stationary source is adding a emissions unit or modifying an existing emissions unit, the State's SIP-approved minor NSR program that permits physical modifications of existing minor sources would govern. As explained previously, section 116 of the CAA allows States to enforce their own emissions limitation and standards if such requirements are not less stringent than the approved SIP and Federal regulations under sections 111 and 112 of the CAA. However, nothing in section 116 prevents a State from revising its SIP to make its requirements less stringent, provided the new requirements are not less stringent than Federal regulations under sections 111 and 112 and meet all other applicable requirements. Nothing in this rule authorizes States to adopt changes that are less stringent than what is required under sections 111 and 112, and therefore section 116 does not limit a State's ability to revise its SIP to adopt these changes. Finally, in response to comments, we have analyzed the impact of this rule and discussed our findings in section IV.E. of this preamble. VI. Effective Date of This Rule and Requirements for State or Tribal Implementation Plans and Title V These changes will take effect in the Federal PSD and part 71 permit programs on July 2, 2007. This means that we will apply these rules in any area without a SIP-approved PSD program or title V program, for which we are the permitting authority, or for which we have delegated our authority to issues permits to a State, local, or tribal permitting authority. We are establishing these requirements as minimum program elements of the PSD, nonattainment NSR, and title V programs. Notwithstanding this requirement, it may not be necessary for a State, local or tribal authority to revise its SIP or title V programs to begin to implement these changes. Some State, local or tribal authorities may be able to adopt these changes through a change in interpretation of the term “chemical process plant” without the need to revise the SIP or the title V program. For any State, local or tribal agency that can implement the changes without revising its approved NSR or title V program, the changes will become effective when the permitting authority publicly announces that it has accepted these changes by interpretation. Although we find that no SIP or title V program revisions may be necessary in certain areas that are able to adopt these changes by interpretation, we encourage such State, local and tribal authorities in such areas to make such SIP or title V program changes in the future to enhance the clarity of the existing rules. For areas that revise their SIPs or title V programs to adopt these changes, the changes are not effective in such area until we approve the SIP revision or title V program as meeting all applicable requirements. Revisions to title V programs to reflect the changes in this rule should be submitted to EPA for approval within 3 years. State, local, or tribal authorities may adopt or maintain NSR program elements that have the effect of making their regulations more stringent than these rules. VII. Statutory and Executive Order Reviews A. Executive Order 12866—Regulatory Planning and Review Under Executive Order
(EO)12866 (58 FR 51735, October 4, 1993), the Agency must determine whether the regulatory action is “significant” and therefore subject to Office of Management and Budget
(OMB)review and the requirements of the Executive Order. Pursuant to the terms of Executive Order 12866, it has been determined that this rule is a “significant regulatory action” because it raises policy issues arising from the President's priorities. Also, this rule is not “economically significant.” Accordingly, the EPA submitted this action to OMB for review under Executive Order 12866 and any changes made in response to OMB's recommendations have been documented in the docket for this action. B. Paperwork Reduction Act This action does not impose any new information collection burden as the burden imposed by this rule has already been taken into account in previously-approved information collection requirement actions under both the NSR and title V programs. The OMB has previously approved the information collection requirements contained in the existing 40 CFR parts 51 and 52 regulations under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 *et seq.* , and has assigned OMB control number 2060-0003, EPA ICR number 1230.17. The OMB has also previously approved the information collection requirements contained in the existing 40 CFR parts 70 and 71 regulations under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 *et seq.* , and has assigned OMB control number 2060-0243 (EPA ICR number 1587.06) to the part 70 rule and OMB control number 2060-0336 (ICR Number 1713.05) to the part 71 rule respectively. A copy of the OMB-approved Information Collection Requests (ICR's), EPA ICR numbers 1230.17, 1587.06, and 1713.05, may be obtained from Susan Auby, Collection Strategies Division; U.S. Environmental Protection Agency (2822T); 1200 Pennsylvania Avenue, NW., Washington, DC 20460 or by calling
(202)566-1672. It is necessary that certain records and reports be collected by a State or local agency (or the EPA Administrator in non-delegated areas), for example, to:
(1)Confirm the compliance status of stationary sources, including identifying any stationary sources subject/not subject to the rule, and
(2)ensuring that the stationary source control requirements are being achieved. The information is then used by the EPA or State enforcement personnel to ensure that the subject sources are applying the appropriate control technology and that the control requirements are being properly operated and maintained on a continuous basis. Based on the reported information, the State, local, or tribal agency can decide which plants, records, or processes should be inspected. Such information collection requirements for sources and States are currently reflected in the approved ICR's referenced above for the NSR and title V programs. Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, disclose, or provide information to or for a Federal agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information; processing and maintaining information; disclosing and providing information; adjusting the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose the information. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. C. Regulatory Flexibility Analysis The Regulatory Flexibility Analysis
(RFA)generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the Agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of this action on small entities, a small entity is defined as:
(1)A small business that is a small industrial entity as defined in the U.S. Small Business Administration
(SBA)size standards (see 13 CFR 121.201);
(2)a small governmental jurisdiction that is a government of a city, county, town, school district, or special district with a population of less than 50,000; or
(3)a small organization that is any not-for-profit enterprise that is independently owned and operated and is not dominant in its field. There are an estimated 114 ethanol production facilities in the U.S. and an estimated 70 more under construction with several more being planned. Most of these facilities use corn as the primary feedstock. It is estimated that farmer-owned cooperatives make up nearly half of the ethanol plants in the U.S. with an additional percentage of facilities under construction that are locally-controlled. ( *http://ethanol.org/production.html* ). After considering the economic impacts of these final amendments on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. Note that the EPA does not know the number of ethanol plants that are (or will be) considered small entities; however, we believe this final rule will not have a significant economic impact on any ethanol plants because its overall impact will be to lessen the requirements that apply to such plants. Additionally, the expansion to additional feedstocks in the production of ethanol reduces the potential economic disparity among ethanol plants regardless of the carbohydrate feedstock used. Additionally, it is important to note that there are currently no commercial scale (other than commercial demonstration plants under construction for cellulosic biomass ethanol production) facilities using sugar beet, sugar cane, or cellulosic biomass feedstocks in the U.S. D. Unfunded Mandates Reform Act Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104-4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local, and tribal governments and the private sector. Under section 202 of the UMRA, the EPA generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with “Federal mandates” that may result in expenditures to State, local, and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any 1 year. Before promulgating an EPA rule for which a written statement is needed, section 205 of the UMRA generally requires EPA to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost-effective or least burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are inconsistent with applicable law. Moreover, section 205 allows EPA to adopt an alternative other than the least costly, most cost-effective or least burdensome alternative if the Administrator publishes with the final rule an explanation as to why that alternative was not adopted. Before EPA establishes any regulatory requirements that may significantly or uniquely affect small governments, including tribal governments, it must have developed under section 203 of the UMRA a small government agency plan. The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of EPA regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements. This rule contains no Federal mandates (under the regulatory provisions of Title II of the UMRA) for State, local, or tribal governments or the private sector. The EPA has determined that this rule does not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any one year. Thus, this rule is not subject to the requirements of sections 202 and 205 of the UMRA. E. Executive Order 13132—Federalism Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure “meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications.” “Policies that have federalism implications” is defined in the Executive Order to include regulations that have “substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.” Under section 6(b) of Executive Order 13132, EPA may not issue a regulation that has federalism implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by State and local governments, or EPA consults with State and local officials early in the process of developing the proposed regulation. Under section 6(c) of Executive Order 13132, EPA may not issue a regulation that has federalism implications and that preempts State law, unless the Agency consults with State and local officials early in the process of developing the proposed regulation. EPA has concluded that this final rule will not have federalism implications. It will not impose substantial direct compliance costs on State or local governments, nor will it preempt State law. Thus, the requirements of sections 6(b) and 6(c) of the Executive Order do not apply to this rule. In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, the EPA specifically solicited comment on the proposed rule from State and local officials. F. Executive Order 13175—Consultation and Coordination With Indian Tribal Governments Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (65 FR 13175, November 9, 2000), requires EPA to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.” This final rule does not have tribal implications, as specified in Executive Order 13175, as there are no tribal authorities currently issuing PSD, major nonattainment NSR, title V permits, or synthetic minor limits to ethanol plant which process carbohydrate feedstocks. Thus, Executive Order 13175 does not apply to this rule. Although Executive Order 13175 does not apply to this final rule, EPA specifically solicited comment on the proposed rule from tribal officials. G. Executive Order 13045—Protection of Children From Environmental Health Risks and Safety Risks Executive Order 13045, entitled “Protection of Children from Environmental Health Risks and Safety Risks” (62 FR 19885, April 23, 1997), applies to any rule that:
(1)Is determined to be “economically significant” as defined under Executive Order 12866; and
(2)concerns an environmental health or safety risk that EPA has reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria, the Agency must evaluate the environmental health or safety effects of the planned rule on children, and explain why the planned regulation is preferable to other potentially effective and reasonably feasible alternatives considered by the Agency. EPA interprets Executive Order 13045 as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5-501 of the Executive Order has the potential to influence the regulation. This final rule is not subject to Executive Order 13045 because it is not “economically significant” as defined in Executive Order 12866 and because the Agency does not have reason to believe the environmental health or safety risks addressed by this action present a disproportionate risk to children. H. Executive Order 13211—Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use These final amendments do not constitute a “significant energy action” as defined in Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001), because they will not likely have a significant adverse effect on the supply, distribution, or use of energy. I. National Technology Transfer and Advancement Act As noted in the proposed rule, section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law 104-113, 12(d) (15 U.S.C. 272 note), directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (for example, materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. The NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards. These final rule amendments do not involve technical standards. Therefore, EPA did not consider the use of any voluntary consensus standards. J. Executive Order 12898—Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations Executive Order 12898 (59 FR 7629 (Feb. 16, 1994)) establishes Federal executive policy on environmental justice. Its main provision directs Federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, any disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States. The EPA has determined that this final rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations. The reason for EPA's determination is because the final rule does not affect the level of protection provided to human health or the environment as it does not change a permitting authority's obligation to maintain the NAAQS, even though changes are being made to the PSD, major nonattainment NSR, and title V programs. K. Congressional Review Act The Congressional Review Act, 5 U.S.C. 801 *et seq.* , as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. EPA will submit a report containing this rule and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication of the rule in the **Federal Register** . A major rule cannot take effect until 60 days after it is published in the **Federal Register** . These final rule amendments do not constitute a “major rule” as defined by 5 U.S.C. 804(2). Therefore, this rule will be effective July 2, 2007. VIII. Judicial Review Under section 307(b)(1) of the Act, judicial review of this final action is available by filing of a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit by July 2, 2007. Any such judicial review is limited to only those objections that are raised with reasonable specificity in timely comments. Under section 307(b)(2) of the Act, the requirements of this final action may not be challenged later in civil or criminal proceedings brought by us to enforce these requirements. List of Subjects 40 CFR Parts 51 and 52 Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Nitrogen dioxide, Ozone, Particulate matter, Reporting and recordkeeping requirements, Sulfur oxides. 40 CFR Parts 70 and 71 Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements. Dated: April 12, 2007. Stephen L. Johnson, Administrator. For reasons stated in the preamble, title 40, chapter I of the Code of Federal Regulations is amended as follows: PART 51—[AMENDED] 1. The authority citation for part 51 continues to read as follows: Authority: 23 U.S.C. 101; 42 U.S.C. 7401-7671q. Subpart I—[Amended] 2. Section 51.165 is amended by revising paragraphs (a)(1)(iv)(C)( *20* ) and (a)(4)(xx) to read as follows: § 51.165 Permit requirements.
(a)* * *
(1)* * *
(iv)* * *
(C)* * * ( *20* ) Chemical process plants—The term chemical processing plant shall not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140;
(4)* * *
(xx)Chemical process plants—The term chemical processing plant shall not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140; 3. Section 51.166 is amended by revising paragraphs (b)(1)(i)( *a* ), (b)(1)(iii)( *t* ), and (i)(1)(ii)( *t* ) to read as follows: § 51.166 Prevention of significant deterioration of air quality.
(b)* * * (1)(i) * * * ( *a* ) Any of the following stationary sources of air pollutants which emits, or has the potential to emit, 100 tons per year or more of any regulated NSR pollutant: Fossil fuel-fired steam electric plants of more than 250 million British thermal units per hour heat input, coal cleaning plants (with thermal dryers), kraft pulp mills, portland cement plants, primary zinc smelters, iron and steel mill plants, primary aluminum ore reduction plants (with thermal dryers), primary copper smelters, municipal incinerators capable of charging more than 250 tons of refuse per day, hydrofluoric, sulfuric, and nitric acid plants, petroleum refineries, lime plants, phosphate rock processing plants, coke oven batteries, sulfur recovery plants, carbon black plants (furnace process), primary lead smelters, fuel conversion plants, sintering plants, secondary metal production plants, chemical process plants (which does not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140), fossil-fuel boilers (or combinations thereof) totaling more than 250 million British thermal units per hour heat input, petroleum storage and transfer units with a total storage capacity exceeding 300,000 barrels, taconite ore processing plants, glass fiber processing plants, and charcoal production plants;
(iii)* * * ( *t* ) Chemical process plants—The term chemical processing plant shall not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140;
(i)* * *
(1)* * *
(ii)* * * ( *t* ) Chemical process plants—The term chemical processing plant shall not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140; Appendix S to Part 51—[Amended] 4. Appendix S to Part 51 is amended by revising paragraphs II.A.4.(iii)( *t* ), and II.F.(20) to read as follows: Appendix S to Part 51—Emission Offset Interpretative Ruling II. * * * A. * * * 4. * * *
(iii)* * * ( *t* ) Chemical process plants—The term chemical processing plant shall not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140; F. * * *
(20)Chemical process plants—The term chemical processing plant shall not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140; PART 52—[AMENDED] 5. The authority citation for part 52 continues to read as follows: Authority: 42 U.S.C. 7401, *et seq.* Subpart A—[Amended] 6. Section 52.21 is amended by revising paragraphs (b)(1)(i)( *a* ), (b)(1)(iii)( *t* ) and (i)(1)(vii)( *t* ) to read as follows: § 52.21 Prevention of significant deterioration of air quality.
(b)* * * (1)(i) * * * ( *a* ) Any of the following stationary sources of air pollutants which emits, or has the potential to emit, 100 tons per year or more of any regulated NSR pollutant: Fossil fuel-fired steam electric plants of more than 250 million British thermal units per hour heat input, coal cleaning plants (with thermal dryers), kraft pulp mills, portland cement plants, primary zinc smelters, iron and steel mill plants, primary aluminum ore reduction plants (with thermal dryers), primary copper smelters, municipal incinerators capable of charging more than 250 tons of refuse per day, hydrofluoric, sulfuric, and nitric acid plants, petroleum refineries, lime plants, phosphate rock processing plants, coke oven batteries, sulfur recovery plants, carbon black plants (furnace process), primary lead smelters, fuel conversion plants, sintering plants, secondary metal production plants, chemical process plants (which does not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140), fossil-fuel boilers (or combinations thereof) totaling more than 250 million British thermal units per hour heat input, petroleum storage and transfer units with a total storage capacity exceeding 300,000 barrels, taconite ore processing plants, glass fiber processing plants, and charcoal production plants;
(iii)* * * ( *t* ) Chemical process plants—The term chemical processing plant shall not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140;
(i)* * *
(1)* * *
(vii)* * * ( *t* ) Chemical process plants—The term chemical processing plant shall not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140; PART 70—[AMENDED] 7. The authority citation for part 70 continues to read as follows: Authority: 42 U.S.C 7401, *et seq.* 8. Section 70.2 is amended by revising paragraph (2)(xx) of the definition of “Major source” to read as follows: § 70.2 Definitions. *Major source* * * *
(2)* * *
(xx)Chemical process plants—The term chemical processing plant shall not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140; PART 71—[AMENDED] 9. The authority citation for part 71 continues to read as follows: Authority: 42 U.S.C 7401, *et seq.* Subpart A—[Amended] 10. Section 71.2 is amended by revising paragraph (2)(xx) of the definition of “Major source” to read as follows: § 71.2 Definitions. *Major source* * * *
(2)* * *
(xx)Chemical process plants—The term chemical processing plant shall not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140; [FR Doc. E7-7365 Filed 4-30-07; 8:45 am] BILLING CODE 6560-50-P 72 83 Tuesday, May 1, 2007 Proposed Rules Part V Department of Housing and Urban Development 24 CFR Part 983 Project-Based Voucher Rents for Units Receiving Low-Income Housing Tax Credits; Proposed Rule DEPARTMENT OF HOUSING AND URBAN DEVELOPMENT 24 CFR Part 983 [Docket No. FR-5034-P-01] RIN 2577-AC62 Project-Based Voucher Rents for Units Receiving Low-Income Housing Tax Credits AGENCY: Office of the Assistant Secretary for Public and Indian Housing, HUD. ACTION: Proposed rule. SUMMARY: This proposed rule would revise the low-income housing tax credit (LIHTC) rent provisions of HUD's final Project-Based Voucher
(PBV)program rule, which was published on October 13, 2005, and took effect on November 14, 2005. The October 13, 2005, final rule capped the PBV rents at the LIHTC rent in buildings with LIHTC units, even in cases where HUD formerly permitted such units to receive the higher rents permitted under the PBV program. After giving the issue further consideration, HUD now proposes to revert to the regulations that address this specific issue and were in effect prior to issuance of the October 13, 2005, final rule. The regulations in effect prior to the October 13, 2005, final rule did not necessarily require public housing agencies
(PHAs)to cap section 8 maximum rents at the tax credit rent. PHAs may not enter into assistance contracts until HUD or an independent entity approved by HUD has conducted the required subsidy layering review and determined that the assistance is in accordance with HUD requirements. DATES: *Comment Due Date:* July 2, 2007. ADDRESSES: Interested persons are invited to submit comments regarding this proposed rule to the Regulations Division, Office of General Counsel, Department of Housing and Urban Development, 451 Seventh Street, SW., Room 10276, Washington, DC 20410-0500. Interested persons may also submit comments electronically through the federal electronic rulemaking portal at: *http://www.regulations.gov* . HUD strongly encourages commenters to submit their comments electronically through *http://www.regulations.gov* . The comments received through this portal are posted and can be easily viewed. Facsimile
(FAX)comments are not acceptable. All communications must refer to the docket number and title. All comments and communications submitted will be available, without revision, for public inspection and copying between 8 a.m. and 5 p.m. weekdays at the above address. Due to security measures at the HUD Headquarters building, an advance appointment to review the public comments must be scheduled by calling the Regulations Division at
(202)708-3055 (this is not a toll-free number). Copies of the public comments submitted electronically are also available for inspection and downloading at *http://www.regulations.gov* . FOR FURTHER INFORMATION CONTACT: David Vargas, Director, Office of Voucher Programs, Department of Housing and Urban Development, 451 Seventh Street, SW., Room 4210, Washington, DC 20410; telephone
(202)708-2815 (this is not a toll-free number). Persons with hearing or speech impairments may access these numbers via TTY by calling the Federal Information Relay Service at
(800)877-8339. SUPPLEMENTARY INFORMATION: I. Background On October 13, 2005, HUD published a final rule that comprehensively revised the regulations for HUD's PBV program, found in 24 CFR part 983. (See 70 FR 59892 *et seq.* ) A detailed description of the legislative background and changes made to the program can be found in the preamble to the October 13, 2005, final rule. Prior to the November 14, 2005, effective date of the October 13, 2005, final rule, PBV units with LIHTCs located outside of qualified census tracts could have rents set at the higher of 110 percent of the area fair market rent
(FMR)or the LIHTC rent charged for comparable units in the same building that receive the tax credit and no other assistance. In other words, in areas where the tax credit rent was higher ( *i.e.* , in the relatively lower-market-rent areas), the units would receive the benefit of that higher rent, but in areas where the FMR was higher ( *i.e.* , in higher-market-rent areas), the units would not be capped at the tax credit rent and instead could receive the higher FMR-based rent. The October 13, 2005, final rule changed this practice, in place for several years, under section 8(o)(13)(H) of the 1937 Act (42 U.S.C. 1437f(o)(13)(H)). The October 13, 2005, final rule provided, under § 983.304(c)(1)(v) and § 983.304(c)(2), that rent for units with tax credit may not exceed the tax credit rent in those cases where formerly, if the FMR-based rent were higher, that higher rent could be used. Since the publication of the October 13, 2005, final rule, HUD received additional comments from PHAs and housing industry representatives expressing concern that the policy change regarding LIHTC units would impede rather than promote HUD's goal of increasing and preserving affordable housing, and requesting that HUD return to its original policy and position regarding LIHTC units. Some PHA and housing industry representatives also advised that the policy change may make many projects relying on LIHTCs non-viable because it could inhibit the financing of new projects by reducing the potential project rent, and thereby reduce the supply of low-income housing using LIHTCs. After further consideration of this issue, HUD has determined that the policy change in the October 13, 2005, final rule concerning LIHTCs may not further HUD's mission to increase affordable housing as effectively as contemplated. While the change would cap federal subsidies, HUD hears the concerns that the change may inhibit the financing of new projects and possibly reduce, not increase, the supply of low-income housing using LIHTCs. HUD believes that concerns about excess federal subsidy may be adequately addressed using subsidy layering analysis. In this regard, HUD has determined that it would benefit by further public input on this issue. This rule therefore proposes to reinstate the former policy in § 983.304(c) with respect to LIHTCs. In response to the public feedback received on the October 13, 2005, final rule, HUD has decided not to enforce § 983.304(c) as revised by the October 13, 2005, final rule. Instead, HUD will await further comment on this issue, as provided by this proposed rule, and will implement the final rule that results from this proposed rulemaking. In the meantime, owners who received a written notification of owner selection subsequent to the effective date of the final rule (November 14, 2005) and have entered into a Housing Assistance Payment
(HAP)contract may request a redetermination of initial rents in accordance with § 983.301 of the final rule, if the initial rents were capped under the tax credit rent provision at § 983.304(c)(1)(v). II. This Proposed Rule For the reasons provided in Section I of this preamble, this proposed rule would remove the requirement added to § 983.304(c) by the October 13, 2005, final rule that PHAs in qualified census tracts have their rents limited by the tax credit rent. Therefore, PHAs would not be required to reduce the PBV rent to the owner for LIHTC units merely because of the existence of LIHTCs. HUD or its designee would, however, conduct a subsidy layering review (consistent with longstanding HUD practice), which could result in rent reductions for projects with LIHTCs and PBV assistance. This review would be consistent with the prior policy. HUD is not proposing to revise or remove any other provision of the October 13, 2005, final rule. III. Findings and Certifications Executive Order 12866, Regulatory Planning and Review The Office of Management and Budget
(OMB)reviewed this proposed rule under Executive Order 12866 (entitled “Regulatory Planning and Review”). OMB determined that this rule is a “significant regulatory action,” as defined in section 3(f) of the Executive Order (although not economically significant, as provided in section 3(f)(1) of the Executive Order). The docket file is available for public inspection between the hours of 8 a.m. and 5 p.m. in the Regulations Division, Office of General Counsel, Department of Housing and Urban Development, 451 Seventh Street, SW., Room 10276, Washington, DC 20410-0500. Due to security measures at the HUD Headquarters building, an advance appointment to review the public comments must be scheduled by calling the Regulations Division at
(202)708-3055 (this is not a toll-free number). Regulatory Flexibility Act The Regulatory Flexibility Act (5 U.S.C. 601 *et seq.* )
(RFA)generally requires an agency to conduct a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements, unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. This proposed rule, as with the prior rulemaking that led to the October 13, 2005, final rule, remains exclusively concerned with PHAs that have chosen to “project-base” 20 percent of their Housing Choice Voucher program assistance. Under the definition of “Small governmental jurisdiction” in section 601(5) of the RFA, the provisions of the RFA are applicable only to those few PHAs that are part of a political jurisdiction with a population of under 50,000 persons. There are very few small PHAs in that category. In addition, this rule would cover only an even smaller category of PHAs—those with PBV HAP contracts for units also receiving LIHTCs. The number of entities potentially affected by this rule is therefore not substantial. Notwithstanding HUD's determination that this rule will not have a significant economic impact on a substantial number of small entities, HUD specifically invites comments regarding any less burdensome alternatives to this rule that will meet HUD's objectives as described by this preamble. Environmental Impact This interim rule involves establishment of external administrative or fiscal requirements related to a rate or cost determination, which does not constitute a development decision affecting the physical condition of specific project areas or building sites. Accordingly, under 24 CFR 50.19(c)(6), this interim rule is categorically excluded from environmental review under the National Environmental Policy Act of 1969 (42 U.S.C. 4321 *et seq.* ). Executive Order 13132, Federalism Executive Order 13132 (entitled “Federalism”) prohibits, to the extent practicable and permitted by law, an agency from promulgating a regulation that has federalism implications and either imposes substantial direct compliance costs on state and local governments and is not required by statute, or preempts state law, unless the relevant requirements of section 6 of the Executive Order are met. This proposed rule does not have federalism implications and does not impose substantial direct compliance costs on state and local governments or preempt state law within the meaning of the Executive Order. Unfunded Mandates Reform Act Title II of the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4; approved March 22, 1995)
(UMRA)establishes requirements for federal agencies to assess the effects of their regulatory actions on state, local, and tribal governments, and on the private sector. This proposed rule does not impose any federal mandates on any state, local, or tribal governments, or on the private sector, within the meaning of the UMRA. Catalog of Federal Domestic Assistance The Catalog of Federal Domestic Assistance number applicable to the program affected by this proposed rule is 14.871. List of Subjects in 24 CFR Part 983 Grant programs—housing and community development, Housing, Low- and moderate-income housing, Rent subsidies, Reporting and recordkeeping requirements. For the reasons stated in the preamble, HUD proposes to amend 24 CFR part 983 to read as follows: PART 983—PROJECT-BASED VOUCHER
(PBV)PROGRAM 1. The authority citation for part 983 continues to read as follows: Authority: 42 U.S.C. 1437f and 3535(d). 2. Revise § 983.304(c) to read as follows: § 983.304 Other subsidy: effect on rent to owner.
(c)*Subsidized projects* .
(1)This paragraph
(c)applies to any contract units in any of the following types of federally subsidized project:
(i)An insured or non-insured Section 236 project;
(ii)A formerly insured or non-insured Section 236 project that continues to receive Interest Reduction Payment following a decoupling action;
(iii)A Section 221(d)(3) below market interest rate
(BMIR)project;
(iv)A Section 515 project of the Rural Housing Service;
(v)Any other type of federally subsidized project specified by HUD.
(2)The rent to owner may not exceed the subsidized rent (basic rent) as determined in accordance with requirements for the applicable federal program listed in paragraph (c)(1) of this section. Dated: March 23, 2007. Orlando J. Cabrera, Assistant Secretary for Public and Indian Housing. [FR Doc. E7-8135 Filed 4-30-07; 8:45 am] BILLING CODE 4210-67-P 72 83 Tuesday May 1, 2007 Rules and Regulations Part VI Library of Congress Copyright Royalty Board 37 CFR Part 380 Digital Performance Right in Sound Recordings and Ephemeral Recordings; Final Rule LIBRARY OF CONGRESS Copyright Royalty Board 37 CFR Part 380 [Docket No. 2005-1 CRB DTRA] Digital Performance Right in Sound Recordings and Ephemeral Recordings AGENCY: Copyright Royalty Board, Library of Congress. ACTION: Final rule and order. SUMMARY: The Copyright Royalty Judges, on behalf of the Copyright Royalty Board of the Library of Congress, are announcing their final determination of the rates and terms for two statutory licenses, permitting certain digital performances of sound recordings and the making of ephemeral recordings, for the period beginning January 1, 2006, and ending on December 31, 2010. DATES: *Effective date:* May 1, 2007. *Applicability date:* The regulations apply to the license period January 1, 2006 through December 31, 2010. ADDRESSES: The final determination is also posted on the Copyright Royalty Board Web site at *http://www.loc.gov/crb/proceedings/2005-1/final-rates-terms2005-1.pdf.* FOR FURTHER INFORMATION CONTACT: Richard Strasser, Senior Attorney, or Gina Giuffreda, Attorney Advisor. *Telephone:*
(202)707-7658. Telefax:
(202)252-3423. SUPPLEMENTARY INFORMATION: I. Introduction A. Subject of the Proceeding This is a rate determination proceeding convened under 17 U.S.C. 803(b) *et seq.* and 37 CFR 351 *et seq.* , in accord with the Copyright Royalty Judges' Notice announcing commencement of proceeding, with a request for Petitions to Participate in a proceeding to determine the rates and terms for a digital public performance of sound recordings by means of an eligible nonsubscription transmission or a transmission made by a new subscription service under section 114 of the Copyright Act, as amended by the Digital Millennium Copyright Act (“DMCA”), and for the making of ephemeral copies in furtherance of these digital public performances under section 112, as created by the DMCA, published at 70 FR 7970 (February 16, 2005). The rates and terms set in this proceeding apply to the period of January 1, 2006 through December 31, 2010. 17 U.S.C. 804(b)(3)(A). B. Parties to the Proceeding The parties to this proceeding are:
(i)Digital Media Association and certain of its member companies that participated in this proceeding, namely: America Online, Inc. (“AOL”), Yahoo!, Inc. (“Yahoo!”), Microsoft, Inc. (“Microsoft”), and Live365, Inc. (“Live365”) (collectively referred to as “DiMA”);
(ii)“Radio Broadcasters” (this designation was adopted by the parties): namely, Bonneville International Corp., Clear Channel Communications, Inc., National Religious Broadcasters Music License Committee (“NRBMLC”), Susquehanna Radio Corp.;
(iii)SBR Creative Media, Inc. (“SBR”) and the “Small Commercial Webcasters” (this designation was adopted by the parties): namely, AccuRadio, LLC, Digitally Imported, Inc., Radioio.com LLC, Discombobulated, LLC, 3WK, LLC, Radio Paradise, Inc.;
(iv)National Public Radio, Inc. (“NPR”), Corporation for Public Broadcasting-Qualified Stations (“CPB”), National Religious Broadcasters Noncommercial Music License Committee (“NRBNMLC”), Collegiate Broadcasters, Inc. (“CBI”), Intercollegiate Broadcasting System, Inc., (“IBS”), and Harvard Radio Broadcasting, Inc. (“WHRB”);
(v)Royalty Logic, Inc. (“RLI”); and
(vi)SoundExchange, Inc. (“SoundExchange”). DiMA, Radio Broadcasters, Small Commercial Webcasters, SBR, NPR, CPB, NRBNMLC, CBI, IBS and WHRB are sometimes referred to collectively as “the Services.” The Services are Internet webcasters or broadcast radio simulcasters that each employ a technology known as streaming, but comprise a range of different business models and music programming. DiMA and certain of its member companies that participated in the proceeding (namely: AOL, Yahoo!, Microsoft and Live365), Radio Broadcasters, SBR and Small Commercial Webcasters are sometimes referred to collectively as “Commercial Webcasters.” NPR, CPB, NRBNMLC, CBI, IBS and WHRB are sometimes referred to collectively as “Noncommercial Webcasters.” II. The Proceedings A. Pre-Hearing Proceedings A notice calling for the filing of Petitions to Participate in this proceeding to set the rates and terms for the period beginning January 1, 2006, and ending on December 31, 2010, was published February 16, 2005. 70 FR 7970. The Petitions were due by March 18, 2005. Forty-two petitions were filed. Following an order to file a Notice of Intention to Submit Written Direct Statements, the participants were reduced to the following twenty eight: SBR; NPR; NPR Member Stations; CPB; CBI; SoundExchange; RLI; IBS; WHRB; Digital Media Association; AOL; Live365; Microsoft; Yahoo!; AccuRadio LLC; Discombobulated LLC; Digitally Imported, Inc.; Radioio.com LLC; Radio Paradise, Inc.; Educational Media Foundation; NRBNMLC; Bonneville International Corp.; Clear Channel Communications, Inc.; CBS Radio, Inc.; NRBMLC; Salem Communications Corp.; Susquehanna Radio Corp.; and Beethoven.com LLC. Following an unsuccessful negotiation period, the Written Direct Statements were due October 31, 2005. All of the above filed plus the additional following: Mvyradio.com LLC; 3WK; XM Satellite Radio, Inc.; Sirius Satellite, Inc.; Infinity Broadcasting Corp. B. The Direct Cases The participants conducted discovery and then began live testimony. By the time testimony began, the participants reduced to the following: SBR; NPR; NPR Member Stations; CPB; CBI; SoundExchange; RLI; IBS; WHRB; Digital Media Association; AOL; Yahoo!; AccuRadio LLC; Discombobulated LLC; Digitally Imported, Inc.; Mvyradio.com LLC; Radioio.com LLC; Radio Paradise, Inc.; 3WK LLC; Educational Media Foundation; NRBNMLC; Bonneville International Corp.; Clear Channel Communications, Inc.; NRBMLC; and Susquehanna Radio Corp. Testimony was taken from May 1, 2005, through August 7, 2006. SoundExchange presented the testimony of the following 14 witnesses:
(1)John Simson, SoundExchange, executive director;
(2)Barrie Kessler, SoundExchange, chief operating officer;
(3)James Griffin, One House LLC, chief executive officer;
(4)Erik Brynjolfsson, MIT Sloan School of Management, professor of management and director of Center for eBusiness at MIT;
(5)Michael Pelcovits, MiCRA, economic consultant;
(6)Mark Eisenberg, SONY BMG, senior vice president of business and legal affairs;
(7)Lawrence Kenswil, Universal eLabs, a division of Universal Music Group, president;
(8)Michael Kushner, Atlantic Records Group, business and legal affairs;
(9)Stephen Bryan, Warner Music Group, vice president of strategic planning and business development;
(10)Harold Bradley, American Federation of Musicians of United States and Canada, vice president;
(11)Jonatha Brooke, songwriter and performer, owner of Bad Dog Records;
(12)Cathy Fink, songwriter and performer;
(13)Bruce Iglauer, Alligator Records, an independent blues label, founder; and
(14)Mark Ghuneim, Wiredset, LLC, chief executive officer. Royalty Logic, Inc. presented the testimony of Ronald A. Gertz, president. The Services presented the testimony of the following 24 witnesses: Digital Media Association and its Member Companies:
(1)Adam B. Jaffe, Brandeis University, professor in economics;
(2)Christine Winston, America Online, executive director of programming strategy and planning;
(3)David Porter, Live365, general manager of business development;
(4)Jonathan Potter, DiMA, executive director;
(5)N. Mark Lam, Live365, chairman and chief executive officer;
(6)Robert D. Roback, Yahoo! Music, general manager;
(7)J. Donald Fancher, Deloitte and Touche Financial Advisory Services LLP;
(8)Jay Frank, Yahoo!, programming and label relations;
(9)Fred Silber, Microsoft, business development manager for MSN;
(10)Eric Ronning, Ronning Lipset Radio;
(11)Jack Isquith, American Online Music, executive director Music Industry Relations;
(12)Karyn Ulman, Music Reports, Inc.; Radio Broadcasters:
(13)Dan Halyburton, Susquehanna Radio, research, engineering and programming;
(14)Roger Coryell, San Francisco Bonneville Radio Group, director strategic marketing and Internet;
(15)Russell Hauth, National Radio Broadcasters Music Licensing Committee, executive director;
(16)Brian Parsons, Clear Channel Radio, vice president of technology; Small Commercial Webcasters:
(17)Kurt Hanson, AccuRadio, president and RAIN newsletter, publisher; National Public Radio:
(18)Kenneth Stern, NPR, chief executive officer; Intercollegiate Broadcasting System, Inc. and Harvard Radio Broadcasting Co., Inc.:
(19)Frederick J. Kass, Jr., IBS, chief operating officer;
(20)Michael Papish, HRBC, treasurer and Media Unbound, president; Collegiate Broadcasters, Inc.:
(21)William Robedee, CBI, past chair and KTRU, Rice University, manager;
(22)Joel R. Willer, KXUL, University of Louisiana, Monroe, faculty advisor; National Religious Broadcasters Noncommercial Music Licensing Committee:
(23)Eric Johnson, NRBNMLC, board member and CDR Radio Network, music director; and SBR Creative Media, Inc.:
(24)David Rahn, president. C. The Rebuttal Cases The participants filed Written Rebuttal Statements on September 29, 2006. Discovery was then conducted on the rebuttal evidence. Rebuttal testimony was taken from November 6 through November 30, 2006. SoundExchange presented the testimony of the following nine witnesses:
(1)Barrie Kessler, SoundExchange, chief operating officer;
(2)James Griffin, One House LLC, chief executive officer;
(3)Erik Brynjolfsson, MIT Sloan School of Management, professor of management and director of Center for eBusiness at MIT;
(4)Michael Pelcovits, MiCRA, economic consultant;
(5)Mark Eisenberg, SONY BMG, senior vice president of business and legal affairs;
(6)Thomas Lee, American Federation of Musicians, president;
(7)Simon Wheeler, Association of Independent Music, chair of New Media Committee;
(8)Charles Ciongoli, Universal Music Group, North American, executive vice president and chief financial officer; and
(9)Tom Rowland, Universal Music Enterprises, senior vice president, film and television music; Royalty Logic, Inc. presented the testimony of the following two witnesses:
(1)Ronald A. Gertz, president; and
(2)Peter Paterno, entertainment attorney; The Services presented the testimony of the following 16 witnesses: Digital Media Association and its Member Companies:
(1)Adam B. Jaffe, Brandeis University, professor in economics;
(2)Christine Winston, America Online, executive director of programming strategy and planning;
(3)N. Mark Lam, Live365, chairman and chief executive officer;
(4)Robert D. Roback, Yahoo! Music, general manager;
(5)J. Donald Fancher, Deloitte and Touche Financial Advisory Services LLP;
(6)Jay Frank, Yahoo!, programming and label relations;
(7)Jack Isquith, American Online Music, executive director Music Industry Relations;
(8)Roger James Nebel, FTI Consulting; Radio Broadcasters:
(9)Keith Meehan, Radio Music Licensing Committee, executive director;
(10)Eugene Levin, Radio Music Licensing Committee, controller;
(11)Brian Parsons, Clear Channel Radio, vice president of technology;
(12)Adam B. Jaffe, Brandeis University, professor of economics; National Public Radio:
(13)Adam B. Jaffe, Brandeis University, professor of economics; Intercollegiate Broadcasting System, Inc. and Harvard Radio Broadcasting Co., Inc.:
(14)Jerome Picard, economics professor (ret.);
(15)Michael Papish, HRBC, treasurer; and National Religious Broadcasters Noncommercial Music Licensing Committee:
(16)Eric Johnson, member of board. At the close of all the evidence, the record was closed. In addition to the written direct statements and written rebuttal statements, the Copyright Royalty Judges heard 48 days of testimony, which filled 13,288 pages of transcript, and 192 exhibits were admitted. The docket contains 475 entries of pleadings, motions and orders. D. Post-Hearing Submissions and Arguments After the evidentiary phase of the proceeding, the participants were ordered to file Proposed Findings of Fact and Conclusions of Law on December 12, 2006, and Responses to those proposals on December 15, 2006. The parties were also ordered to submit Stipulated Terms on December 15, 2006, but none have been filed. Closing arguments were heard on December 21, 2006. Then the matter was submitted to the Copyright Royalty Judges for a Determination. 1 1 Hereinafter, references to written direct testimony shall be cited as “WDT” preceded by the last name of the witness and followed by the page number. References to written rebuttal testimony shall be cited as “WRT” preceded by the last name of the witness and followed by the page number. References to the transcript record shall be cited as “Tr.” preceded by the date and followed by the page number and the last name of the witness. References to proposed findings of fact and conclusions of law shall be cited as “PFF” or “PCL,” respectively, preceded by the name of the party that submitted same and followed by the paragraph number. References to reply proposed findings of fact and conclusions of law shall be cited as “RFF” or “RCL,” respectively, preceded by the name of the party and followed by the paragraph number. On March 2, 2007, the Copyright Royalty Judges issued the initial Determination of Rates and Terms. Pursuant to 17 U.S.C. 803(c)(2) and 37 CFR Part 353, the parties filed Motions for Rehearing. 2 The Judges requested the parties to respond to the motions filed, in order to know the positions of each party on each of the issues raised in the motions, and ordered the parties to file written arguments in support of each motion. The parties filed responses and written arguments. Having reviewed all motions, written arguments and responses, the Judges denied all the motions for rehearing. Order Denying Motions for Rehearing, In the Matter of Digital Performance Right in Sound Recordings and Ephemeral Recordings, Docket No. 2005-1 CRB DTRA (April 16, 2007). As reviewed in the said Order, none of the grounds in the motions presented the type of exceptional case where the Determination is not supported by the evidence, is erroneous, is contrary to legal requirements, or justifies the introduction of new evidence. 17 U.S.C. 803(c)(2)(A); 37 CFR 353.1 and 353.2. The motions did not meet the required standards set by statute, by regulation and by case law. Nevertheless, the Judges were persuaded to clarify two issues raised by the parties. This Final Determination includes a transition phase for 2006 and 2007 to use Aggregate Tuning Hours (“ATH”) to estimate usage as permitted under the prior fee regime. This limited use of an ATH calculation option should facilitate a smooth transition to the fee structure adopted in this Final Determination. Next, the regulations are corrected to refer to “digital audio transmissions” in place of the phrase “Internet transmissions.” III. The Statutory Criteria for Setting Rates and Terms 2 Motions were filed by DiMA, IBS, WHRB, NPR, Radio Broadcasters, RLI, Small Commercial Webcasters, SoundExchange and CBI. A. The Statutory Background 1. Music Copyright Law in General Section 102 of the Copyright Act of 1976 (the “Copyright Act”) identifies various categories of works that are eligible for copyright protection. 17 U.S.C. 102. These include “musical works” and “sound recordings.” *Id.* at 102(2) and 102(7). The term “musical work” refers to the notes and lyrics of a song, while a “sound recording” results from “the fixation of a series of musical, spoken, or other sounds.” *Id.* at 101. A song that is sung and recorded will constitute a sound recording by the entity that records the performance, and a musical work by the songwriter. Another performer may record the same song and that performance will result in another sound recording, but the musical work remains with the songwriter. Under these facts, there are two sound recordings and one musical work as a result of the two recordings of the same song. Typically, a record label owns the copyright in a sound recording and a music publisher owns the copyright in a musical work. 5/4/06 Tr. 24:11-27:16 (Simson). Under the 1976 Copyright Act, a copyright owner receives a bundle of exclusive rights set forth in section 106. 17 U.S.C. 106. Among them is the right to make or authorize the performance to the public of a copyrighted work. The performance right is granted to all categories of copyrighted works with one exception: Sound recordings. Thus, while the owner of a musical work enjoys the performance right, the owner of a sound recording does not. 3 Congress did not begin to address this inequality until the end of the twentieth century. 3 Indeed, copyright owners of musical works have enjoyed the performance right since the nineteenth century. 2. The DPRA In 1995, Congress enacted the Digital Performance Right in Sound Recordings Act (“DPRA”), Public Law 104-39, 109 Stat. 336 (1995), which added a new section 106(6) to the Copyright Act. That provision grants copyright owners of sound recordings a limited performance right to make or authorize the performance of their works “by means of a digital audio transmission.” 17 U.S.C. 106(6). Often referred to as the “digital performance right,” the right was further limited by the creation of a statutory license for certain nonexempt, noninteractive subscription services and preexisting satellite digital audio radio services. 17 U.S.C. 114. The statutory license permits these services, upon compliance with certain statutory conditions, to make those transmissions without obtaining consent from, or having to negotiate license fees with, copyright owners of the sound recordings they perform. *Id.* Congress established procedures to facilitate voluntary negotiation of rates and terms including a provision authorizing copyright owners and services to designate common agents on a nonexclusive basis to negotiate licenses—as well as to pay, to collect, and to distribute royalties— and a provision granting antitrust immunity for such actions. *Id.* Absent agreement among all the interested parties, the Librarian of Congress was directed to convene a Copyright Arbitration Royalty Panel (“CARP”) to recommend royalty rates and terms. Congress directed the CARP to set a royalty rate for the subscription services' statutory license that achieves the policy objectives in section 801(b)(1) of the Copyright Act. *Id.* Under the DPRA, copyright owners must allocate one-half of the statutory licensing royalties that they receive from the subscription services to recording artists. Forty-five percent of these royalties must be allocated to featured artists; 2 1/2 percent of the royalties must be distributed by the American Federation of Musicians to non-featured musicians; and 2 1/2 percent of the royalties must be distributed by the American Federation of Television and Radio Artists to non-featured vocalists. 17 U.S.C. 114(g). 3. The DMCA The new statutory license for digital audio transmission of sound recordings was expanded in the Digital Millennium Copyright Act of 1998 (“DMCA”), Public Law 105-304, 112 Stat. 2860 (1998). It provided that certain digital transmissions and retransmissions, typically referred to as webcasting, are subject to the section 106(6) digital performance right and that webcasters who transmit/retransmit sound recordings on an interactive basis, as defined in section 114(j), must obtain the consent of, and negotiate fees with, individual owners of those recordings. However, webcasting would be eligible for statutory licensing when done on a *non-interactive* basis. Accordingly, Congress created another statutory license in sections 114(d)(2) & (f)(2) for “eligible nonsubscription transmissions,” which include non-interactive transmissions of sound recordings by webcasters. 17 U.S.C. 114(d)(2). To qualify for that license, the webcaster must comply with several conditions in addition to those that the DPRA applied to preexisting subscription and satellite radio services. As with these service royalties, webcaster royalties are allocated on a 50-50 basis to copyright owners and to performers. Congress adopted the DPRA voluntary negotiation and arbitration procedures for the DMCA webcaster performance license. 17 U.S.C. 114(e), (f). However, it changed the statutory standard for determining rates and terms. The new standard is to determine what “most clearly represent the rates and terms that would have been negotiated in the marketplace between a willing buyer and a willing seller.” 17 U.S.C. 114(f)(2)(B). Congress also recognized that webcasters who avail themselves of the section 114 license may need to make one or more temporary or “ephemeral” copies of a sound recording in order to facilitate the transmission of that recording. Accordingly, Congress created a new statutory license in section 112(e) for such copies and extended that license to services that transmit sound recordings to certain business establishments under the section 114(d)(1)(c)(iv) exemption created by the DPRA. Congress retained the DPRA voluntary negotiation and arbitration procedures for the section 112 ephemeral license. 17 U.S.C. 112(e)(2), (3). Congress again applied the willing buyer/willing seller standard applicable to the section 114 webcaster performance license. 17 U.S.C. 112(e)(4). The webcasting and ephemeral statutory licenses created by the DMCA are the subject of this proceeding. The two DMCA licenses were the subject of one prior proceeding. Determination of Reasonable Rates and Terms for the Digital Performance of Sound Recordings and Ephemeral Recordings (Final Rule), 67 FR 45240 (July 8, 2002) (codified at 37 CFR part 261) (“Webcaster I”). After a recommendation from a CARP, the Librarian applied the statutory standard to determine rates and terms. Many of the parties in this proceeding participated in that prior proceeding. 4. The Reform Act Congress enacted a new system to administer copyright royalties with the Copyright Royalty and Distribution Reform Act of 2004 (the “Reform Act”), Public Law 108-419, 118 Stat. 2341. The Copyright Royalty Judges were established to perform the functions previously served by the Copyright Royalty Tribunal and the Librarian of Congress. They were appointed January 9, 2006, and took over this proceeding. B. Section 114(f)(2) 1. The Statutory Language The criteria for setting rates and terms for the section 114 webcaster performance license are enunciated under 17 U.S.C. 114(f)(2)(B), which provides in pertinent part: * * * Such rates and terms shall distinguish among the different types of eligible nonsubscription transmission services then in operation and shall include a minimum fee for each such type of service, such differences to be based on criteria including, but not limited to, the quantity and nature of the use of sound recordings and the degree to which use of the service may substitute for or may promote the purchase of phonorecords by consumers. In establishing rates and terms for transmissions by eligible nonsubscription services and new subscription services, the Copyright Royalty Judges shall establish rates and terms that most clearly represent the rates and terms that would have been negotiated in the marketplace between a willing buyer and a willing seller. In determining such rates and terms, the Copyright Royalty Judges shall base [their] decision on economic, competitive and programming information presented by the parties, including—
(i)whether use of the service may substitute for or may promote the sales of phonorecords or otherwise may interfere with or may enhance the sound recording copyright owner's other streams of revenue from its sound recordings; and
(ii)the relative roles of the copyright owner and the transmitting entity in the copyrighted work and the service made available to the public with respect to relative creative contribution, technological contribution, capital investment, cost, and risk. 17 U.S.C. 114(f)(2)(B). The statute further directs the Judges to set “a minimum fee for each such type of service” and grants the Judges discretion to consider the rates and terms for “comparable types of digital audio transmission services and comparable circumstances under voluntary license agreements” negotiated under the voluntary negotiation provisions of the statute. *Id.* 2. The Relationship of the Statutory Factors to the “Willing Buyer/Willing Seller” Standard Webcaster I clarified the relationship of the statutory factors to the willing buyer/willing seller standard. The standard requires a determination of the rates that a willing buyer and willing seller would agree upon in the marketplace. In making this determination, the two factors in section 114(f)(2)(B)(i) and
(ii)must be considered, but neither factor defines the standard. They do not constitute additional standards, nor should they be used to adjust the rates determined by the willing buyer/willing seller standard. The statutory factors are merely to be considered, along with other relevant factors, to determine the rates under the willing buyer/willing seller standard. Webcaster I; In re Rate Setting for Digital Performance Right in Sound Recordings and Ephemeral Recordings, No. 2000-9 CARP DTRA 1 & 2 (“Webcaster I Carp Report”). 3. The Nature of “The Marketplace” The parties agree that the directive to set rates and terms that “would have been negotiated” in the marketplace between a willing buyer and a willing seller reflects Congressional intent for the Judges to attempt to replicate rates and terms that “would have been negotiated” in a hypothetical marketplace. Webcaster I CARP Report at 21. The “buyers” in this hypothetical marketplace are the Services (and other similar services) and this marketplace is one in which no statutory license exists. *Id.* See also Noncommercial Educational Broadcasting Compulsory License (Final rule and order), 63 FR 49823, 49835 (September 18, 1998) (“[I]t is difficult to understand how a license negotiated under the constraints of a compulsory license, where the licensor has no choice but to license, could truly reflect ‘fair market value.’ ”). The “sellers” in this hypothetical marketplace are record companies, and the product being sold consists of a blanket license for the record companies' complete repertoire of sound recordings. Webcaster I, 67 FR 45244 (July 8, 2002). 4. The Appropriate Willing Buyer/Willing Seller Rate As noted, the statute directs us to “establish rates and terms that *most clearly* represent the rates and terms that would have been negotiated in the marketplace.” 17 U.S.C. 114(f)(2)(B) (emphasis added). In the hypothetical marketplace we attempt to replicate, there would be significant variations, among both buyers and sellers, in terms of sophistication, economic resources, business exigencies, and myriad other factors. Congress surely understood this when formulating the willing buyer/willing seller standard. Accordingly, the Judges construe the statutory reference to rates that “most clearly represent the rates * * * that would have been negotiated in the marketplace” as the rates to which, absent special circumstances, most willing buyers and willing sellers would agree. Webcaster I, 67 FR 45244, 45245 (July 8, 2002); Webcaster I CARP Report at 25, 26. C. Section 112(e) The criteria for setting rates and terms for the section 112 ephemeral license are enunciated under 17 U.S.C. 112(e)(4), which provides in pertinent part: The Copyright Royalty Judges shall establish rates that most clearly represent the fees that would have been negotiated in the marketplace between a willing buyer and a willing seller. In determining such rates and terms, the Copyright Royalty Judges shall base their decision on economic, competitive, and programming information presented by the parties, including—
(A)whether use of the service may substitute for or may promote the sales of phonorecords or otherwise interferes with or enhances the copyright owner's traditional streams of revenue; and
(B)the relative roles of the copyright owner and the transmitting organization in the copyrighted work and the service made available to the public with respect to relative creative contribution, technological contribution, capital investment, cost, and risk. 17 U.S.C. 112(e)(4). As does section 114, this section further directs the Judges to set “a minimum fee for each type of service.” 17 U.S.C. 112(e)(4). Although section 112 does not explicitly grant the Judges discretion to consider the rates and terms for comparable types of services, it does explicitly grant discretion to “consider the rates and terms under voluntary license agreements” negotiated under the provisions of the statute. 17 U.S.C. 112(e)(4). Accordingly, while the language of the two sections varies in minor respects, the Judges interpret the criteria for setting rates and terms as essentially identical. See Webcaster I Order of July 16, 2001, at 5. IV. Determination of Royalty Rates A. Application of Section 114 and Section 112 Based on the applicable law and relevant evidence received in this proceeding, the Copyright Royalty Judges must determine rates for two licenses, the section 114 webcaster performance license and the section 112 ephemeral reproduction license. The Copyright Act requires that the Copyright Royalty Judges establish rates for each of these two licenses that most clearly represent those “that would have been negotiated in the marketplace between a willing buyer and a willing seller” and directs the Copyright Royalty Judges to set a minimum fee for each license. In the case of both licenses, the Copyright Act requires the Copyright Royalty Judges to take into account evidence presented on such factors as
(1)whether the use of the webcasting services may substitute for or promote the sale of phonorecords and
(2)whether the copyright owner or the service provider make relatively larger contributions to the service ultimately provided to the consuming public with respect to creativity, technology, capital investment, cost and risk. 17 U.S.C. 114(f)(2)(B) and 17 U.S.C. 112 (e)(4). Having carefully considered the relevant law and the evidence received in this proceeding, the Copyright Royalty Judges determine that the appropriate section 114 performance license rate is a per performance usage rate for Commercial Webcasters and an annual flat per-station rate for Noncommercial Webcasters for use up to a specified cap coupled with a per performance rate for use above the cap, while the appropriate section 112 reproduction license rate is deemed to be included in the applicable respective section 114 license rates. The applicable rate structure is the starting point for the Copyright Royalty Judges' determination. B. The Rate Proposals of the Parties and the Appropriate Royalty Structure for Section 114 Performance Licenses 1. Commercial Webcasters The contending parties present several alternative rate structures for Commercial Webcasters. In its final revised rate proposal, SoundExchange argues in favor of a monthly fee equal to the greater of: 30% of gross revenues or a performance rate beginning at $.0008 per performance in 2006 and increasing annually to $.0019 by 2010. 4 This fee structure is proposed for nonsubscription services and is modified to add a third alternative in its “greater of” formulation of a $1.37 per subscriber minimum for new subscription services. 5 An exception to this “greater of” formulation is proposed for so-called “bundled services” from which SoundExchange seeks a per performance rate of $.002375 to be adjusted each year by the change in the CPI-U. SoundExchange's Revised Rate Proposal (filed September 29, 2006) at 2-12. 4 The latter $.0019 per performance rate is to be adjusted by the change in the CPI-U from December 2005 to December 2009 (accordingly, if the CPI-U increases by 3% in each of these four twelve-month periods, the resulting per performance rate for 2010 would increase from $.0019 to $.00214). 5 In addition, SoundExchange proposes an adjustment to its revenue alternative based on time spent listening to music for so-called “non-music” services, a per performance rate of $.002375 to be adjusted each year by the change in the CPI-U for “bundled services” and a 25% premium for transmissions terminating on wireless devices for nonsubscription services, new subscription services and bundled services. By contrast, DiMA on behalf of certain large commercial webcasters, proposes a fee structure under which webcasters could elect a fee equal to either $.00025 per performance or $.0038 per Aggregate Tuning Hour (“ATH”) or 5.5% of revenue directly associated with the streaming service. However, DiMA applies only its per performance usage rate to “bundled services” situations where the bundle price to the consumer is not allocated as between the individual component parts of the bundle. DiMA PFF at ¶¶ 35-38. Smaller commercial webcasters present varying proposals. SBR Creative Media, Inc., a privately owned commercial webcaster, proposes a fee structure under which webcasters can elect a fee equal to either a use metric of $.0033 per Aggregate Tuning Hour (“ATH”) or 4% of gross revenue. SBR Creative Media PFF at ¶ 19. The self-styled Small Commercial Webcasters, 6 in contrast to all the other commercial parties, propose a pure revenue-based metric equal to 5% of gross revenues. Small Commercial Webcasters PCL at ¶ 24. 6 The Small Commercial Webcasters are AccuRadio, LLC; Digitally Imported, Inc.; Radioio.com, LLC; Discombobulated, LLC; 3WK, LLC and Radio Paradise, Inc. Radio Broadcasters propose an annual flat fee 7 structure generally related to usage as reflected in the format of the radio station being simulcast over the web. For example, Radio Broadcasters propose that music-formatted stations pay a fee ranging from as little as $500 per annum for small stations in low revenue ranked markets to as much as $8,000 per annum for large stations in high revenue ranked markets, but further propose that news, talk, sports and/or business stations pay $250 per annum irrespective of station size in low revenue ranked markets and $750 per annum irrespective of station size in high revenue ranked markets. Finally, Radio Broadcasters propose that stations with mixed music/non-music formats pay a percentage of the music format fee, depending on the percentage of programming identified as music programming. Radio Broadcasters PFF at ¶¶ 325-338. 7 Radio Broadcasters further propose that the structure increase across the board by 4% annually over the term of the license. In short, among the parties on both sides who have proposed rates covering Commercial Webcasters, only Small Commercial Webcasters propose a fee structure based solely on revenue. However, in making their proposal, this group of five webcasters clearly is unconcerned with the actual structure of the fee, except to the extent that a revenue-based fee structure especially one in which the percent of revenue fee is a single digit number (i.e., 5%)—can protect them against the possibility that their costs would ever exceed their revenues. 8 Their only witness, Kurt Hanson, CEO/President of AccuRadio, LLC, in fact, provided testimony indicating that the Small Commercial Webcasters were, at bottom, concerned with the amount of the fee rather than the structure of the fee. (“Obviously, were there to be a sound recording royalty based on performances that was at an extremely low rate * * * a percentage-of-revenue model might not be required. And just as obviously, a confiscatory percentage-of-revenue rate would not allow these companies [the Small Commercial Webcasters] to survive.”) Hanson, WDT at 4 n.2. Small Commercial Webcasters' focus on the amount of the fee, rather than how it should be structured, is further underlined by the absence of evidence submitted by this group to identify a basis for applying a pure revenue-based structure to them. While, at times, they suggest that their situation as small commercial webcasters requires this type of structure, there is no evidence in the record about how the Copyright Royalty Judges would delineate between small webcasters and large webcasters. 9 Similarly, while Mr. Hanson asserts that a percentage-of-revenue is necessary because “this is a nascent industry” or because small entrepreneurs require such a structure, 8/3/06 Tr. 49:12-22 (Hanson), he offers no evidence to support that assertion or to help define the parameters of the assertion. Furthermore, the only other self-styled small entrepreneur to offer testimony in this proceeding, SBR Creative Media Inc., specifically includes a usage metric in its rate proposal and neither SBR Creative Media, Inc. nor the Small Commercial Webcasters offers any evidence to distinguish between their respective situations. 8 It must be emphasized that, in reaching a determination, the Copyright Royalty Judges cannot guarantee a profitable business to every market entrant. Indeed, the normal free market processes typically weed out those entities that have poor business models or are inefficient. To allow inefficient market participants to continue to use as much music as they want and for as long a time period as they want without compensating copyright owners on the same basis as more efficient market participants trivializes the property rights of copyright owners. Furthermore, it would involve the Copyright Royalty Judges in making a policy decision rather than applying the willing buyer/willing seller standard of the Copyright Act. 9 Indeed, since none of the small commercial webcasters participating in this proceeding provided helpful evidence about what demarcates a “small” commercial webcaster from other webcasters at any given point in time, any determination that a revenue-based metric was somehow uniquely applicable to small commercial webcasters would be speculative. While each of the remaining contending parties—SoundExchange, DiMA, Radio Broadcasters and SBR Creative Media, Inc.—proposes a fee structure for Commercial Webcasters that contains revenue-based elements as well as either usage elements or a usage alternative, from the evidence of record, the Copyright Royalty Judges conclude that numerous factors weigh in favor of a per-performance usage fee structure for Commercial Webcasters. First, as aptly stated by Dr. Adam Jaffe, revenue merely serves as “a proxy” for what “we really should be valuing, which is performances.” Jaffe, WDT Section N, Designated Testimony (Jaffe WDT in Webcaster I at 22). By contrast, a per-performance metric “is directly tied to the nature of the right being licensed, unlike other bases such as revenue * * * of the licensee.” *Id.* (Emphasis in original.) The more intensively an individual service is used and consequently the more the rights being licensed are used, the more that service pays and in direct proportion to the usage. 10 Jaffe, WDT Section N, Designated Testimony (Jaffe WDT in Webcaster I at 21-22). As Dr. Jaffe points out, with a usage metric, the resultant “scaling” of the royalty paid to the extent of use “is intuitively appealing and is a common feature” of intellectual property licenses. Jaffe, WDT at 32. Dr. Jaffe notes that, by contrast, “Revenue is a less exact proxy for the scale of activity, because the revenue that a licensee derives, even from its music-related activities can be influenced by a variety of factors that have nothing to do with music.” *Id.* Therefore, Dr. Jaffe cautions that a revenue-based metric should only be used as a proxy for a usage-based metric where the revenue base used for royalty calculation is “carefully defined to correspond as closely as possible to the intrinsic value of the licensed property.” *Id.* The Copyright Royalty Judges do not find a sufficient clarity of evidence based on the record in this proceeding to produce a revenue-based metric that can serve as a good proxy for a usage-based metric. Furthermore, there was no persuasive evidence offered by any commercial webcasting/simulcasting party to indicate that a usage-based metric is not readily calculable and, that as a consequence, the Copyright Royalty Judges must resort to some proxy metric in reaching their fee determination. 10 Dr. Erik Brynjolfsson is similarly of the opinion that “the rates paid by a given company should take into account that different companies use different amounts of music.” 11/21/06 Tr. 251:2-18 (Brynjolfsson). Second, percentage-of-revenue models present measurement difficulties because identifying the relevant webcaster revenues can be complex, such as where the webcaster offers features unrelated to music. Webcaster I noted this particular difficulty. 67 FR 45249 (July 8, 2002). Mixed format webcasters/simulcasters continue to make up a significant part of the commercial webcasting market and, in a number of cases, generate the more significant portion of their revenues from non-music programming. RBX1; RBX7; RBX20; 7/27/06 Tr. 283:7-285:12 (Hauth). Clearly, questions surrounding the proper allocation of revenues related to music use in such instances present greater complexity than a straightforward use of a usage-based approach. 11 11 This is illustrated in the SoundExchange rate proposal where an additional adjustment is made to the proposed revenue rate where services conform to a definition of “non-music services” as measured by the listening time of end users. By contrast, in the same rate proposal no such adjustment needs to be made to the proposed usage rate for the same services. The added information necessary for the adjustment as well as the process of adjustment to the revenue-based metric clearly would raise the transaction costs of implementing a revenue rate structure as compared to the usage-based metric. SoundExchange's Revised Rate Proposal (filed September 29, 2006) at 11-12. Third, percentage of revenue metrics ultimately demand a clear definition of revenue so as to properly relate the fee to the value of the rights being provided, and no such clear definition has been proffered by the parties. Indeed, the definition of revenue has been a point of substantial contention between two of the parties in this proceeding. SoundExchange sought an expansive definition of revenue, ostensibly covering revenues from subscription fees, advertisements (of many kinds including advertisements directly and indirectly derived from webcasting), sales of products and commissions from third party sales, software fees and sales of data. SoundExchange's Revised Rate Proposal (filed September 29, 2006) at 12-17. But the Copyright Royalty Judges are not persuaded that all the elements of the SoundExchange definition of revenue have been shown, in every instance, to be related to the use of the rights provided to licensees. 12 For example, there is some evidence presented by the Radio Broadcasters that on-air talent, programming director contributions and marketing skills impact the revenues of simulcasting webcasters. Radio Broadcasters PFF at ¶¶ 234, 237, 240. DiMA has proposed a much more restrictive definition of revenue as part of its rate proposal which it seeks to support through the testimony of its witness, Donald Fancher. On the whole, we find little to recommend Mr. Fancher's testimony, but the Copyright Royalty Judges do observe that even Mr. Fancher conceded that, on various points, the DiMA proposed definition was unclear. 6/22/06 Tr. 292:11-295:14; 308:1-309:1; 311:15-312:10; 315:17-317:14 (Fancher). The absence of persuasive evidence of what constitutes an unambiguous definition of revenue that properly relates the fee to the value of the rights being provided militates against reliance on a revenue-based metric. 12 Moreover, the mere process of measuring such an expansive array of revenues must necessarily raise transaction costs for the parties. Fourth, the use of a revenue-based metric gives rise to difficult questions for purposes of auditing and enforcement related to payment for the use of the license. The per-performance approach involves the relatively straightforward application of a rate to reports of use (recordkeeping) data that is already required to be produced by the Services. See 37 CFR part 370. While audit and enforcement issues may arise even with a pure usage metric, the alternative use of a revenue-based metric will give rise to additional, different issues of interpretation and controversy related to how revenues are defined or allocated. See, for example, Radio Broadcasters PFF at ¶ 258 and 7/31/06 Tr. 78:3-11, 79:1-13 (Parsons). In other words, the introduction of multiple payment systems will augment the transactions costs imposed on the parties. Fifth, the way that the contending parties, in particular SoundExchange and DiMA, suggest using a revenue-based metric in their rate proposals does not square with the basic notion agreed to by their respective experts (Dr. Brynjolfsson for SoundExchange and Dr. Jaffe for DiMA) that the more the rights being licensed are used, the more payments should increase in direct proportion to usage. See supra at Section IV.B.1. SoundExchange seeks to use the revenue-based metric to insure that it will share in any revenue produced by the Services that is greater than what it would receive based on a usage rate coupled with actual usage. Pelcovits WDT at 28. This could result in a situation where the Services would be forced to share revenues that are not attributable to music use, but rather to other creative or managerial inputs. DiMA, on the other hand, seeks to employ a revenue-based metric to protect against the failure of revenues produced by the Services (particularly as they pursue a shift to advertising-supported business models) to rise to the level necessary to pay for music use based on actual usage. Winston WDT at 10. This could result in a situation in which copyright owners are forced to allow extensive use of their property without being adequately compensated due to factors unrelated to music use such as a dearth of managerial acumen at one or more Services. The similar potentiality that webcasters might generate little revenue and, under a revenue-based metric, produce a situation where copyright owners receive little compensation for the extensive use of their property was a concern that animated the Librarian to approve a per performance metric rather than providing for a revenue-based payment option in Webcaster I. 67 FR 45249 (July 8, 2002). For all of the above reasons, the Copyright Royalty Judges conclude that evidence in the record weighs in favor of a per-performance usage fee structure for Commercial Webcasters. This does not mean that some revenue-based metric could not be successfully developed as a proxy for the usage-based metric at some time in the future by the parties if the problems noted above were remedied. It does mean that the parties to this proceeding have not overcome these problems in the context of the proposals they have offered in this proceeding. 13 13 While both SoundExchange and DiMA have pointed to a number of agreements covering music rights that embody an alternative revenue-based metric, they have not shown:
(1)Whether those agreements have overcome these problems or,
(2)if so, how those agreements have overcome these problems or,
(3)most importantly, how their proposed rate structures embody comparable mechanisms for overcoming these problems. Nor have they demonstrated whether these other agreements have been negotiated with a revenue-based option in the context of comparable circumstances-for example, an agreement negotiated with a revenue-based alternative because of an inability of some services to account for performances would not be comparable to the circumstances at hand because of our recordkeeping requirements at 37 CFR part 370. A further consequence of the Copyright Royalty Judges rejecting the revenue-based metric as a proxy for a usage-based metric is to eliminate the need for a rate structure formulated as a “greater of” or “lesser of” comparison between per performance metrics and alternative revenue-based metrics. 14 Therefore, the Copyright Royalty Judges determine that a per-performance rate structure will be utilized for eligible nonsubscription transmission services, new subscription services and bundled services and where such services are commercial Services. 14 In addition, while SoundExchange proposes a third alternative—a per subscription minimum dollar amount—to be applied to new subscription services, the Copyright Royalty Judges do not find the basis for this alternative structure to be supported by persuasive evidence. SoundExchange cannot be proposing this per subscription alternative because of a lack of music usage data from subscription services, because the per subscription alternative itself requires such usage data in order to make a pro rata distribution of the per subscription minimum to the record companies. See Pelcovits WDT at 22. Nor does SoundExchange present persuasive evidence that the availability of this per subscription alternative is necessary because it is easier to administer and thus will reduce transaction costs. Indeed, although SoundExchange makes it an alternative to the per-performance fee in its proposed structure, SoundExchange presents its purpose as equivalent to the function served by the per-performance fee in its proposed fee structure. See Pelcovits WDT at 28-29. Moreover, SoundExchange's own expert economist, Dr. Brynjolfsson, further notes that in cases where webcasters “monetize” the value of the sound recording license through subscriptions or advertising revenue, “counting the number of plays is a good proxy” for that value. 5/18/06 Tr. 116:9-117:14 (Brynjolfsson). For all these reasons, the Copyright Royalty Judges decline to establish such a duplicative structure. 2. Noncommercial Webcasters The Copyright Royalty Judges also find that a revenue-based metric is not a good proxy for a usage-based metric as applied to noncommercial webcasters in the non-interactive webcasting marketplace because, in addition to suffering from the same shortcomings discussed supra at Section IV.B.1. in the context of the Commercial Webcasters, 15 no evidence of negotiated agreements applying a revenue-based metric to Noncommercial Webcasters has been presented by any of the parties. 15 Indeed, the use of a revenue-based metric in connection with Noncommercial Webcasters may further exacerbate transactions costs where defining of revenue, accounting for revenue and auditing of such accounts involve different concepts for the noncommercial, non-profit entities that populate this marketplace as compared to the accounting concepts and approaches applicable to commercial entities. For example, NPR derives significant amounts of its revenues from several sources not typically found as a source of commercial service revenue, such as underwriting, donations, public funds and the NPR Foundation. NPR PFF at ¶ 18. Only one party in this proceeding, SoundExchange, proposes that Noncommercial Webcasters should be subject to a rate structure incorporating a revenue-based metric as one alternative means of payment. SoundExchange specifically proposes that Noncommercial Webcasters pay according to the same structure and rates applicable to Commercial Webcasters, previously summarized supra at Section IV.B.1. The Noncommercial Webcasters propose a variety of rates that are (or could be read as) per station flat rates. For example, NPR proposes a flat fee of $80,000 per annum, with successive years after the first year increased by a cost-of-living adjustment as determined by the change in the CPI. NPR proposes that this flat fee cover all NPR
(798)and CPB-qualified stations (estimated at 100 or 200). Stern WDT at 13; 6/27/06 Tr. 154:18-155:18 (Stern). The NRBNMLC proposes that non-commercial, non-NPR music stations pay a flat annual fee consisting of the lesser of
(a)$200 per Internet simulcast and up to two associated side channels or
(b)$500 per group of up to five Internet simulcasts and up to two Internet-only side channels per simulcast. The NRBNMLC further proposes that for news, talk, business, teaching/talk, or sports stations the aforementioned annual fee alternatives drop to $100 and $250 respectively. Mixed format stations would pay a pro rata share of these annual fees based on the demonstrated music-talk programming breakdown. Finally, NRBNMLC proposes that all five years of such fees covering the 2006-2010 license term be paid in one lump sum at the beginning of the term, except that a broadcaster that stops streaming before the end of the term would be entitled to a pro rata refund. 16 NRBNMLC Fee Proposal August 1, 2006. 16 NRBNMLC also proposes a decrease in its annual fees “to match the per station fees of NPR if the NPR station fees are lower than the above-stated fees.” NRBNMLC Fee Proposal August 1, 2006. IBS' amended rate proposal seeks a $100 annual rate for large college stations and a $25 annual rate for smaller college stations. 17 IBS Clarification of Common Rate Proposal (August 10, 2006). 18 CBI proposed a flat annual fee of $175 for educational stations. CBI Amended Introductory Statement at 6. 17 The IBS rates herein summarized were to be applicable only to noncommercial educational stations not covered by the annual lump sum payment proposed by NPR and CPB. 18 IBS' original proposal consisted of a flat fee of $500 per year for music stations and $250 per year for non-music stations, with additional payments in the event that the webcaster exceeded 146,000 aggregate tuning hours in a month. Kass WDT at Ex. A. For the reasons discussed infra at Section IV.C.2.a., the Copyright Royalty Judges determine that Commercial Webcasters and certain Noncommercial Webcasters represent two different segments of the marketplace. In contrast to the general commercial marketplace, agreements produced by the parties in this proceeding covering noncommercial services typically structured payments as flat fees. See, for example, SERV-D-X 157. Furthermore, no evidence was presented by the parties that could be used in a precise way to convert such flat annual fees into a reliable per-performance metric. Consequently, only a per station metric could be ascertained from such flat fees. Flat annual fees do not present the complexity, measurement difficulties, accounting and enforcement issues presented by revenue-based alternatives, and, as a result, do not increase transaction costs beyond what might be experienced under a usage-based fee structure. On the other hand, flat fees do permit increasing usage without increasing payment. However, as noted infra at Section IV.C.2.a, the Copyright Royalty Judges have determined that in order to preserve the distinction between the commercial webcasters and certain noncommercial segments of the marketplace over the period of the license term, a cap on usage must be established for certain noncommercial webcasters. In short, the Copyright Royalty Judges conclude that, on balance, the most appropriate rate structure for noncommercial services that can be reliably derived from the record of evidence is an annual flat per-station rate structure for use by certain noncommercial webcasters up to a specified cap coupled with a per performance rate for use by noncommercial services that exceed the cap. C. The Section 114 Royalty Rates and Minimum Fees 1. Commercial Webcasters a. The “Willing Buyer/Willing Seller Standard” As previously noted hereinabove, supra at Section IV.A., the Copyright Act requires that the Copyright Royalty Judges establish rates for the section 114 performance license that “most clearly” represent those “that would have been negotiated in the marketplace between a willing buyer and a willing seller.” Both the copyright owners and the commercial services agree that the willing buyer/willing seller standard should be applied by the Copyright Royalty Judges in determining the rates for the section 114 license and both the copyright owners and the commercial services agree that those rates should reflect the rates that would prevail in a hypothetical marketplace that was not constrained by a statutory license. Finally, both copyright owners and commercial services agree that the best approach to determining what rates would apply in such a hypothetical marketplace is to look to comparable marketplace agreements as “benchmarks” indicative of the prices to which willing buyers and willing sellers in this marketplace would agree. SoundExchange PFF at ¶¶ 215-219; SoundExchange PCL at ¶¶ 4-27; DiMA and Radio Broadcasters JPFF at ¶¶ 75-80; DiMA and Radio Broadcasters JPCL at ¶¶ 28-9; DiMA PFF at ¶¶ 39-45; Radio Broadcasters PFF at ¶¶ 296-301; SBR Creative Media, Inc. PFF at ¶¶ 17; Small Commercial Webcasters PFF at ¶¶ 24-28. However, the parties, to some extent, appear to disagree about the degree of competition among sellers required by law in the hypothetical marketplace, resulting in different definitions of the sellers in the hypothetical marketplace. 19 SoundExchange accuses the Services of seeking a marketplace characterized by perfect competition. DiMA and the Radio Broadcasters claim that SoundExchange is championing a marketplace characterized by monopoly power on the seller's side. SoundExchange PCL at ¶ 38; DiMA and Radio Broadcasters JPCL at ¶¶ 29, 36. We find that these extreme characterizations miss the mark. 19 For example, at one extreme, if no competition exists on the seller's side of the market (i.e., the seller is a monopolist), then the degree of competition observed describes the number of sellers in the marketplace (i.e., there is a single seller in the marketplace). The question of competition is not confined to an examination of the seller's side of the market alone. Rather, it is concerned with whether market prices can be unduly influenced by sellers' power or buyers' power in the market. This issue was addressed in Webcaster I. An effectively competitive market is one in which super-competitive prices or below-market prices cannot be extracted by sellers or buyers, because both bring “comparable resources, sophistication and market power to the negotiating table.” 67 FR 45245 (July 8, 2002). In other words, neither sellers nor buyers can be said to be “willing” partners to an agreement if they are coerced to agree to a price through the exercise of overwhelming market power. Furthermore, we find that in the hypothetical marketplace that would exist in the absence of a statutory license constraint, the willing sellers are the record companies. Any cognizable entity smaller than the record companies makes little sense because, in such cases, the larger buyers among the Services would enjoy disproportionate market power resulting in below-market prices. At the same time, if the sellers' side of the market were characterized by so many sellers as to be consistent with perfect competition, the transaction costs to the buyers of the copyrights would likely be prohibitive. Webcaster I made clear that “the willing buyers are the services which may operate under the webcasting license (DMCA-compliant services), the willing sellers are record companies and the product consists of a blanket license for each record company which allows use of that record company's complete repertoire of sound recordings.” 67 FR 45244 (July 8, 2002) (emphasis added). None of the parties has adduced persuasive evidence that this definition of sellers has been altered in the marketplace as a result of greater or lesser competition between these sellers since Webcaster I was issued. For example, no party provided any empirical evidence on the elasticity of the demand curve facing these firms in the market or, more importantly, whether it has changed since Webcaster I. Similarly, no party produced persuasive evidence that market share had changed substantially among the record companies in the hypothetical marketplace since Webcaster I. 20 20 Dr. Jaffe presents some testimony implying anti-competitive market share differences and the potentially collusive use of “most-favored-nations” clauses in the interactive music service marketplace. See Jaffe WRT at 6-16. However, the Copyright Royalty Judges do not find Dr. Jaffe's testimony persuasive even with respect to this different marketplace. See infra at Section IV.C.1.b.iii.. As articulated in the Copyright Act, the “willing buyer/willing seller standard” encompasses consideration of economic, competitive and programming information presented by the parties, including
(1)the promotional or substitution effects of the use of webcasting services by the public on the sales of phonorecords and
(2)the relative contributions made by the copyright owner and the webcasting service with respect to creativity, technology, capital investment, cost and risk in bringing the copyrighted work and the service to the public. Because we adopt a benchmark approach to determining the rates, we agree with Webcaster I that such considerations “would have already been factored into the negotiated price” in the benchmark agreements. 67 FR 45244 (July 8, 2002). Therefore, such considerations have been reviewed by the Copyright Royalty Judges in our determination of the most appropriate benchmark from which to set rates. We have further reviewed the evidence bearing on these considerations to determine if the benchmark agreements require any further adjustment based on any evidence of differences between the benchmark market and the target hypothetical market. See infra at Section IV.C.1.c. b. Benchmarks For Setting Market Rates Notwithstanding their general agreement that a benchmark approach is the best way to setting rates in this hypothetical marketplace, the parties disagree about what constitutes the appropriate benchmark indicative of the prices to which willing buyers and willing sellers in this marketplace would agree. SoundExchange maintains that the most appropriate benchmark agreements, as analyzed by its expert economist, Dr. Michael Pelcovits, are those found in the market for interactive webcasting covering the digital performance of sound recordings. SoundExchange PFF at ¶ 216. On the other hand, DiMA, Radio Broadcasters and Small Commercial Webcasters argue that the most appropriate benchmarks are agreements between the performing rights organizations (especially, ASCAP and BMI) and webcasters covering the digital public performance of musical works. DiMA PFF at ¶¶ 39-45; Radio Broadcasters PFF at ¶ 297; Small Commercial Webcasters PFF at ¶¶ 24-26. SBR Creative Media, Inc. claims analog over-the-air broadcast music radio as its benchmark, with reference to musical composition royalties paid by such broadcasters to the performing rights organizations (“PROs”). SBR Creative Media, Inc. Rahn WDT at 11. We find, based on the available evidence before us, that the most appropriate benchmark agreements are those reviewed by Dr. Pelcovits in the market for interactive webcasting covering the digital performance of sound recordings. i. The Interactive Webcasting Market Benchmark The interactive webcasting market is a benchmark with characteristics reasonably similar to non-interactive webcasting, particularly after Dr. Pelcovits' final adjustment for the difference in interactivity. Both markets have similar buyers and sellers and a similar set of rights to be licensed (a blanket license in sound recordings). Both markets are input markets and demand for these inputs is driven by or derived from the ultimate consumer markets in which these inputs are put to use. In these ultimate consumer markets, music is delivered to consumers in a similar fashion, except that, as the names suggest, in the interactive case the choice of music that is delivered is usually influenced by the ultimate consumer, while in the non-interactive case the consumer usually plays a more passive role. Pelcovits WDT at 5-15. But this difference is accounted for in Dr. Pelcovits' analysis. In order to make the benchmark interactive market more comparable to the non-interactive market, Dr. Pelcovits adjusts the benchmark by the added value associated with the interactivity characteristic. Pelcovits WDT at 37-41. In short, the Copyright Royalty Judges find the Pelcovits benchmark to be of the comparable type that the Copyright Act invites us to consider. 17 U.S.C. 114(f)(2)(B) (“In establishing such rates and terms, the Copyright Royalty Judges may consider the rates and terms for comparable types of digital audio transmission services and comparable circumstances under voluntary license agreements negotiated under subparagraph (A).”). ii. SoundExchange's Proposed Corroborative Evidence SoundExchange offers additional relevant evidence from the marketplace for other types of digital music services to corroborate Dr. Pelcovits' analysis by showing that, for many types of music services, a substantial portion of revenue is paid to sound recording copyright owners above the current statutory rate, just as it would be under the rate proposal that Dr. Pelcovits' analysis seeks to support. See, for example, summary chart of Universal Music Group agreements covering various digital music marketplaces at SoundExchange PFF at ¶ 338. We find these additional voluntary agreements covering such digital services as clip licenses, permanent audio downloads, etc. of some general corroborative value. These data show that, in many cases, the price paid by buyers for the rights to utilize a sound recording in various ways is as much as or higher than the rate proposed by Dr. Pelcovits as a result of his benchmark analysis. 21 This shows that the prevailing rates in these other markets do not appear to undermine his analysis—some indication of general reasonableness. 21 Although, little effort is made in the presentation of this corroborative data to reconcile differences that may exist between these markets and adjust for such differences. At the same time, SoundExchange offered further purportedly corroborative testimony by its economic expert, Dr. Brynjolfsson, which seeks to support its rate proposal based on an analysis of costs and revenues related to webcasting and of the “surplus” that would be generated over the course of the license period. Dr. Brynjolfsson testified that one approach to determining the price a seller would obtain in the market is to measure the “surplus” that would be generated when the seller's input is added to the buyer's service and sold to the public, and then to divide that “surplus” between the buyer and the seller. In order to make the division, it is necessary to determine the revenue that would be generated by the retail sale of the service and the service provider's other costs of providing the service (i.e., costs other than expenditures on the input sought to be valued). This requires certain information about the buyer, the seller and the marketplace to determine how the “surplus” would be divided. We find that the Brynjolfsson analysis relies on unsupported assumptions about market behavior and how negotiations take place in obtaining his results. For example, Dr. Brynjolfsson makes a questionable assumption that conditions in the real world justify the use of a 75% licensor to 25% licensee ratio in bargaining power in his models for this market. 5/18/2006 Tr. 120:1-124-3 (Brynjolfsson). No evidence from this market was provided to support this assumption. A different assumption of equal bargaining power would yield a different estimate of the proposed royalty rate. Similarly, other assumptions such as a 20% annual growth rate in the sell-out rates for banner ads and a 10% annual growth rate in the sell-out rate for in-stream advertising are not solidly supported. DiMA and Radio Broadcasters JPFF at ¶¶ 206, 208. Different assumptions for these numbers would clearly provide different bottom-line rate determinations in Dr. Brynjolfsson's models. Then too, Dr. Brynjolfsson inputs data into his models in a less than rigorous fashion. For example, he relies on Accustream data as a source for certain cost data without examining the methodology used by Accustream in compiling the data. 5/18/2006 Tr. 141:1-6 (Brynjolfsson). Dr. Brynjolfsson also uses such data to project future growth rates even though the source, Accustream, does not appear to discuss its methodology for collecting their data in the written report that supplies the data. SERV-D-X 37. Thus, if there is error in the original data stemming from the way it is collected, that error is compounded by applying growth rates to an erroneous base. Dr. Brynjolfsson also appears to have double-counted or miscounted certain types of revenue. DiMA and Radio Broadcasters JPFF at ¶¶ 215, 216. In short, questionable assumptions coupled with concerns over the reliability of the data used in the Brynjolfsson models cause us to regard the ultimate findings of these models as effectively undeterminable. For those reasons, the Copyright Royalty Judges find that the Brynjolfsson models do not provide additional corroboration of SoundExchange's benchmark analysis and the rates proposed. 22 22 We do not intend to imply that all of the evidence offered by Dr. Brynjolfsson through his testimony is without value; rather, we simply find that his two formal models taken as a whole suffer from significant defects for the purposes at hand. iii. Services' Objections to Pelcovits' Interactive Webcasting Market Benchmark Analysis Are Not Persuasive The Services' objections to the Pelcovits benchmark analysis are not supported by persuasive evidence. Their major objections are reflected in Dr. Jaffe's written rebuttal testimony and boil down to two:
(1)The claim that this benchmark market is not adequately competitive and
(2)certain alleged methodological flaws in the Pelcovits approach. Jaffe WRT at 4-24. As we have indicated hereinabove, supra at Section IV.C.1.a., the law does not require a perfectly competitive target market if that is the thrust of Dr. Jaffe's objections; therefore, neither does it require a perfectly competitive benchmark market because that would not be comparable to circumstances in the target market. Indeed, Webcaster I emphasizes that buyers and sellers participate in a “competitive” market for purposes of the law when they have comparable resources and market power. 23 67 FR 45245 (July 8, 2002). 23 In other words, a “competitive” price could be deemed to have been set in a marketplace where sellers and buyers had roughly equal bargaining power, because the resulting price would be much closer to the perfectly competitive price than to a price determined in circumstances where the sellers exercised pure monopoly power or the buyers exercised pure monopsony power. That is, counterveiling power has the effect of yielding a more competitive result than does the absence of such counterveiling power. On the other hand, if the thrust of Dr. Jaffe's concerns are that the benchmark market is not sufficiently competitive to be similar to the competitive circumstances that prevail in the target hypothetical market, we find that the evidence does not support such a view. On the contrary, the evidence establishes that the benchmark market is sufficiently similar to the target hypothetical market to merit comparison. There are multiple sellers and buyers in each market—indeed many are the same buyers and sellers. Pelcovits WDT at 12-13. In other words, the weight of the evidence supports the Pelcovits benchmark analysis. Dr. Jaffe's claim that buyers in the market for interactive webcasting face a different seller than the record companies because they need the portfolios of the four major record companies in order to provide a service to consumers is largely unsubstantiated. 24 Dr. Jaffe himself concedes the possibility for competition among the record companies for market share in the interactive market. SoundExchange PFF at ¶¶ 304-305. 24 Additionally, there was testimony that directly contradicts any suggested generalization that the repertoires of all four majors are necessary as a prerequisite prior to undertaking the operation of a consumer music service in the various digital music service markets. For example, Mr. Roback testified that Yahoo! was able to operate its custom radio channels without Universal Music for two years, even though Universal may account for nearly one-third of the market in terms of repertoire. 11/9/06 Tr. 17:13-21 (Roback). At the same time, Dr. Jaffe's contention that the interactive webcasting benchmark market is highly concentrated on the seller's side is not supported by any evidence of a super-competitive impact on prices in the benchmark market. Further undermining his contention is Dr. Jaffe's own admission that market concentration on one side of the market (i.e., among sellers) need not necessarily result in an outcome that looks markedly different from a competitive outcome so long as the buyers in the same market have comparable market power. SoundExchange PFF at ¶ 196. Nor does Dr. Jaffe provide any persuasive evidence to support a collusion allegation among the sellers in the interactive webcasting benchmark market. SoundExchange PFF at ¶ 312. And he fails to substantiate his claim that the presence of so-called most favored nations (“MFN”) clauses in certain agreements in the interactive webcasting market is suggestive of anti-competitive behavior. MFN clauses are not automatically indicative of tacit collusion—they may simply reflect the need for price flexibility in the face of uncertainty in long-term contracts. 25 25 At the same time, it should be noted that Dr. Pelcovits did review the MFN clauses in the agreements in question and concluded they were not anti-competitive or collusive. 5/15/06 Tr. 207:5-16 (Pelcovits). In short, Dr. Jaffe's concerns that the benchmark market is not sufficiently competitive to be similar to the competitive circumstances that prevail in the target hypothetical market amount to little more than the theoretical speculations of an academic offering a quick outline of possible criticisms without carefully considering the applicable facts or alternative explanations. We find that the available evidence does not support such a view. Apart from his concerns about the competitive comparability of the interactive webcasting market benchmark to the hypothetical target market, Dr. Jaffe also raises methodological criticisms of the projected rate results obtained by Dr. Pelcovits from the latter's use of interactive webcasting as a benchmark. While raising interesting potential issues, Dr. Jaffe's critique fails in its search for persuasive evidence. For example, Dr. Jaffe complains that the interactivity adjustment made by Dr. Pelcovits is based on incorrect and internally inconsistent assumptions—i.e., the assumption that “elasticity at market equilibrium is the same for interactive services and non-interactive services.” Jaffe WRT at 17. First, it should be noted that even if Dr. Jaffe's complaint were supported by the record, it would not eliminate the interactive webcasting market as an appropriate benchmark. As Dr. Pelcovits correctly notes, “if demand elasticity were to differ significantly between the two markets, it could increase the copyright fee or decrease it.” Pelcovits WRT at 36 n.14. But we are not faced with that difficulty here because the available evidence tends to support Dr. Pelcovits' assumption that demand elasticities were likely to be very close in the relevant range of the demand curves. SoundExchange RFF at ¶¶ 117-118; Pelcovits WRT at 25-27. Dr. Jaffe also contends that Dr. Pelcovits improperly extrapolates fees for non-subscription or ad-supported services from a model based entirely on subscription services because subscription services only account for a small percentage of non-interactive services. Jaffe WRT at 22-24. He says, without empirical support, that this small fraction is not representative of all non-interactive listeners. Jaffe WRT at 22-24. The implication is that ad-supported services are the predominant business model now for non-interactive webcasting and that ad-supported services would necessarily pay less than subscription services to use the same music in their non-interactive services because their advertising revenues have not yet grown to the point where ad-supported services are more lucrative on a per-listener hour basis. However, this criticism, besides providing no information on the degree of substitution by consumers between the subscription and non-subscription options, fails to take into account any improvement in ad-supported revenues over the term of this licensing period. SoundExchange PFF at ¶¶ 320-321, 323-324. Therefore, to the extent that ad-supported revenues may not yet have equalized subscription revenues on a per-listener hour basis but are expected to grow over the term of this applicable license, SoundExchange's proposed phase-in of the per-performance rates to the level indicated by the benchmark analysis represents a wholly reasonable approach to dealing with this potential issue. Finally, Dr. Jaffe contends that one or more of the key data items in Dr. Pelcovits' rate analysis must be incorrect because their strict application would produce a negative royalty rate. Jaffe WRT at 20-22. But this criticism ignores the profits earned by interactive services, or, alternatively, assumes without basis that the same dollar amount of profit should be earned by services in the non-interactive market. 26 Jaffe WRT at 20-21; SoundExchange RFF at ¶¶ 122-123. We find no merit in this flawed critique. 26 Dr. Pelcovits also noted that a negative royalty rate would be unlikely to occur in a dynamically adjusting market. Pelcovits WRT at 30. In sum, the Services' objections to the Pelcovits benchmark analysis are not persuasive. This does not mean that Dr. Pelcovits' analysis and presentation is without any warts. For example, Dr. Pelcovits failed to fully account in his written statement for the reasoning behind his choice of variables and the functional form used in his hedonic model to isolate the value of interactivity to consumers of online music services. But for the fact that he subsequently provided most of that information orally in response to questions from the Copyright Royalty Judges, 5/16/2006 Tr. 267:16-276:14 (Pelcovits), such an omission may have led to more serious questions about this aspect of his model. And a more comprehensive study of the relative price elasticities of demand in the interactive and non-interactive webcasting markets would have been a welcome addition to the available evidence on this point, even though the available evidence weighed in Dr. Pelcovits' favor. On the other hand, the Copyright Royalty Judges find that these critiques are not sufficient to undermine the basic thrust and conclusions of the Pelcovits benchmark analysis. Moreover, as noted supra at Section IV.C.1.b.ii., his analysis benefits from some general corroborative evidence. iv. A Flawed Musical Works Benchmark Offered by Dr. Jaffe We have also considered and rejected Dr. Jaffe's offer of agreements from the musical works marketplace as a benchmark. This benchmark analysis appears to be little more than a hasty attempt to revive and rehabilitate some similar arguments that failed to prevail in Webcaster I. The Copyright Royalty Judges find that the benchmark analysis offered by Dr. Jaffe is fatally flawed for several reasons. First, Dr. Jaffe's benchmark analysis is based on a marketplace in which, while the buyers may be the same as in the target hypothetical marketplace, the sellers are different and they are selling different rights. Therefore, contrary to Dr. Jaffe's expectations that the prices paid for the rights in each respective market dealing with similar rights should be the same, substantial empirical evidence shows that sound recording rights are paid multiple times the amounts paid for musical works rights in the markets for ring tones, digital downloads, music videos and clip samples. Pelcovits WRT at 4; Eisenberg WRT at 7-14. Second, the Copyright Royalty Judges find that Dr. Jaffe's equivalence argument also fails because of his reliance on the assumption of “sunk costs” as a justification. This assumption must be rejected on both theoretical and empirical grounds. Dr. Jaffe claims that, while the sellers in his benchmark market are not the same, they come to the negotiation from a similar position because in both his proposed benchmark market and in the hypothetical target market, the costs of producing the underlying intellectual property are “sunk.” Jaffe WDT at 23. According to Dr. Jaffe, this means “there is no incremental cost imposed on either the musical work or sound recording by virtue of making the underlying intellectual property available for digital performance.” 27 Jaffe WDT at 24. As a matter of theory, Dr. Jaffe's proposed benchmark analysis ignores the long-established pattern of investment in the recording industry. Thus, not only are there some initial sunk investments, but there is a requirement of repeated substantial outlays year after year or, in other words, the repeated “sinking” of funds. If sellers are faced with the prospect of not recovering such sunk costs, then the incentive to produce such sound recordings is diminished. And the record is replete with evidence of a substantially greater investment of this type in sound recordings as compared to musical works. SoundExchange PFF at ¶¶ 449-461. Furthermore, recording companies will necessarily make future investment decisions based on their best estimates of the revenue sources available to them in the future from all sources including revenue streams derived from the non-interactive webcasting of sound recordings. 28 SoundExchange PFF at ¶ 478; Brynjolfsson WRT at 6-8. Thus, to suggest that they ignore such costs in their approach to pricing makes little sense. It would be tantamount to suggesting that services such as Yahoo! or AOL or Microsoft would never consider the cost of their research and development programs when pricing their products. 29 In short, we decline to accept Dr. Jaffe's “sunk costs” justification for his proposed benchmark. 27 Curiously, at this point in his analysis Dr. Jaffe appears to back away from his insistence on a “competitive” market because to maintain that position would lead to a logically inconsistent result in his benchmark analysis. Since, in a perfectly competitive market situation, price at equilibrium is equal to marginal cost, then, logically, the price for the rights in question could be no higher than zero. Therefore, Dr. Jaffe opts for a necessarily different undefined market structure by saying that here, even though the price should be zero, the resulting royalty would be some greater amount apparently determined by the relative bargaining power of the buyers and sellers. Jaffe WDT at 26. If this benchmark market results in a price that is higher than what is expected under perfectly competitive conditions, then clearly the sellers must be exercising some degree of market power. 28 In other words, this is not just a static process concerned with recouping past investment costs, but a dynamic economic process concerned with obtaining greater resources for future creative efforts. 29 Indeed, even Dr. Jaffe concedes that the costs of sound recordings not yet created are not sunk. 6/28/06 Tr. 99:7-101-7 (Jaffe). Third, there is ample empirical evidence in the record from other marketplaces to controvert Dr. Jaffe's premise that the market for sound recordings and the market for musical works are necessarily equivalent. SoundExchange PFF at ¶¶ 483-495. For all these reasons, the Copyright Royalty Judges find that Dr. Jaffe's proffered benchmark is not useful to our determination of an appropriate benchmark from which to derive applicable rates. We, therefore, adhere to the Pelcovits benchmark analysis as a superior tool for that purpose. v. Other Proposed Benchmarks Rejected One other benchmark was proposed in this proceeding by a commercial party. SBR Creative Media, Inc. claims analog over-the-air broadcast music radio as its benchmark, with reference to musical composition royalties paid by such broadcasters to the performing rights organizations. SBR Creative Media, Inc. Rahn WDT at 11. We find that this is virtually the same benchmark as that proposed by Dr. Jaffe on behalf of the Services and rejected in Webcaster I. 67 FR 45246-7 (July 8, 2002). SBR does nothing to remedy the deficiencies from which this proposed benchmark was shown to suffer in Webcaster I. Furthermore, this proposed benchmark suffers from the same deficiencies we find fatal with respect to Dr. Jaffe's proposed benchmark discussed supra at Section IV.C.1.b.iv. For all these reasons, the Copyright Royalty Judges find that the SBR Creative Media, Inc. proffered benchmark is not useful to our determination of an appropriate benchmark from which to derive applicable rates and, therefore, adhere to the Pelcovits benchmark analysis as a superior tool for that purpose. c. Conclusion: The Interactive Webcasting Market Benchmark Provides the Best Benchmark for Setting Commercial Rates Without Further Adjustment for Either Substitution or Promotion Factors or the Relative Contributions Made by the Copyright Owners and Webcasting Services in Bringing the Copyrighted Works and the Services to the Public As discussed supra at Section IV.C.1.a., the “willing buyer/willing seller standard” in the Copyright Act encompasses consideration of economic, competitive and programming information presented by the parties, including
(1)the promotional or substitution effects of the use of webcasting services by the public on the sales of phonorecords and
(2)the relative contributions made by the copyright owner and the webcasting service with respect to creativity, technology, capital investment, cost and risk in bringing the copyrighted work and the service to the public. Because we adopt a benchmark approach to determining the rates, we agree with Webcaster I that such considerations “would have already been factored into the negotiated price” in the benchmark agreements. 67 FR 45244 (July 8, 2002). Therefore, such considerations have been reviewed by the Copyright Royalty Judges in our determination of the most appropriate benchmark from which to set rates. Nevertheless, we have also further reviewed the evidence bearing on these considerations to determine if the benchmark agreements require any further adjustment based on any evidence of differences between the benchmark market and the target hypothetical market. We find that no further adjustment is necessary to the Pelcovits benchmark analysis to account for any of these considerations. Dr. Pelcovits explicitly examined the promotion and substitution issues and ultimately found no empirical evidence to suggest a net substitution/promotion difference between the interactive and the non-interactive marketplaces. Pelcovits WRT at 17-27. Because only the relative difference between the benchmark market and the hypothetical target market would necessitate an adjustment, the absence of solid empirical evidence of such a difference obviates the need for such further adjustment. Furthermore, even if the absolute levels of promotion/substitution in the non-interactive market alone were somehow relevant, as the Services appear to suggest, we find that the Services presented no acceptable empirical basis for quantifying promotion/substitution for purposes of adjusting rates in that market. 30 30 For example, the Radio Broadcasters strenuously assert that over-the-air-radio is promotional and therefore that simulcasting must be promotional. But they present no persuasive evidence that would be useful for quantifying the magnitude of this asserted effect either for over-the-air-radio or for non-interactive webcasting and deriving a method for translating such magnitudes into a rate adjustment. Indeed, the quality of evidence presented by the Services on this issue consisted largely of assertions, recollections of conversations clearly evidencing common “puffing” in a business context, or anecdotes recounting subjective opinions. On a similar record, Webcaster I found no basis for a downward adjustment of the simulcast rate to account for the promotional value associated with over-the-air broadcasts because the net impact was indeterminate. 67 FR 45255 (July 8, 2002). Similarly, the parties' evidence with respect to the relative contributions made by the copyright owner and the webcasting service with respect to creativity, technology, capital investment, cost and risk in bringing the copyrighted work and the service to the public does not persuade us that any further adjustment needs to be made to the Pelcovits benchmark to account for quantifiable differences related to these factors. We find that such factors are implicitly accounted for in the rates that result from negotiations between the parties in the benchmark marketplace. Moreover, because only the relative difference between the benchmark market and the hypothetical target market would necessitate an adjustment, the absence of solid empirical evidence of such a difference obviates the need for such further adjustment. Finally, the Radio Broadcasters seek to differentiate their simulcasting operations from the operations of other commercial webcasters and, thereby, obtain a different, lower royalty rate. The record before us fails to persuade us that these simulcasters operate in a submarket separate from and non-competitive with other commercial webcasters. Indeed, there is substantial evidence to the contrary in the record indicating that commercial webcasters such as those represented by DiMA in this proceeding and simulcasters such as those represented by Radio Broadcasters in this proceeding regard each other as competitors in the marketplace. SoundExchange PFF at ¶¶ 1107-1110. Therefore, the Copyright Royalty Judges do not find a basis for setting a different, lower rate for these simulcasters as compared to other commercial webcasters. Webcaster I, at 67 FR 45255, 45272 (July 8, 2002), reached a similar conclusion in finding no basis for treating these simulcasters any differently with respect to the per performance commercial rate, and we find no facts to persuade us of a change in circumstance since then. d. Rates and Minimum Fees Applicable to Commercial Webcasters i. Determination of Per Play Rates for Commercial Webcasters Because we find that the interactive webcasting market is a benchmark with characteristics reasonably similar to non-interactive webcasting, particularly after Dr. Pelcovits' final adjustment for the difference in interactivity, the Copyright Royalty Judges find that this benchmark supports the explicit annual usage rates 31 proposed by SoundExchange. Therefore, we find that the per play rate applicable to each year of the license for Commercial Webcasters 32 is as follows: a per play rate of $.0008 for 2006, a per play rate of $.0011 for 2007, a per play rate of $.0014 for 2008, a per play rate of $.0018 for 2009 and a per play rate of $.0019 for 2010. 33 31 For the reasons indicated supra at Section IV.B.1, only usage rates are determined. 32 Commercial Webcasters include such licensees who are eligible nonsubscription transmission services or new subscription services, irrespective of whether they transmit music in large part or in small part. 33 The Judges recognize that a smooth transition from the prior fee regime to the new fee structure adopted by the Judges hereinabove may be aided by permitting the limited use of an ATH calculation option. Such a transition option enhances the ability of some Services to effectuate speedy payments and, in so doing, improves the ability of copyright owners to more quickly obtain monies due. In short, such a transition measure is reasonably calculated to facilitate a smooth, speedy transition to the new fee structure adopted hereinabove by the Judges. Therefore, the usage fee structure established in this Final Determination will continue use of an ATH option for timely payment of fees due for the years 2006 and 2007. See table near footnote 33 reference. The following Aggregate Tuning Hours
(ATH)usage rate calculation options will be available for the transition period of 2006 and 2007: Note: [See table for footnote 33 above] where “Non-Music Programming” is defined as Broadcaster programming reasonably classified as news, talk, sports or business programming; “Broadcast Simulcast Programming” is defined as Broadcaster simulcast programming not reasonably classified as news, talk, sports or business programming; and “Other Programming” is defined as programming other than either Broadcaster simulcast programming or Broadcaster programming reasonably classified as news, talk, sports or business programming. Other programming Broadcast simulcast programming Non-music programming Prior Fees $0.0117 per ATH $0.0088 per ATH $0.0008 per ATH. 2006 $0.0123 per ATH $0.0092 per ATH $0.0011 per ATH. 2007 $0.0169 per ATH $0.0127 per ATH $0.0014 per ATH. Note: See footnote 33 We find no basis for making further adjustments to this usage rate to reflect inflation 34 or bundling. 35 34 We do not find that the benchmark supports an additional Consumer Price Index adjustment to the usage rate in 2010. No evidence has been submitted by SoundExchange to support this additional adjustment by what is, at this point in time, an indeterminate amount. 35 We find that a usage rate is more directly reflective of the rights being licensed than other alternative rate metrics. See supra at Section IV.B. Moreover, the evidence presented fails to persuade us that receiving a music service as part of a bundle of services necessarily results in a higher valuation of that music service by the consumer than if it had been delivered as a non-bundled service. For example, SoundExchange's claim for an uplifted rate for bundled services is supported by only one custom radio agreement addressing bundled services and that agreement is specifically identified by its expert, Dr. Pelcovits, as part of a class of agreements that are “not a good benchmark.” Pelcovits WRT at 35 n.43. Therefore, we find no sufficient basis upon which to determine a different usage rate for bundled services as compared to non-bundled services. We are persuaded by the evidence in the record to apply these usage rates without any further adjustment for wireless transmission to all Commercial Webcasters. While SoundExchange's proposed rates included a 25% premium for “wireless services,” the Copyright Royalty Judges find no persuasive basis in the record for such a so-called “mobility premium.” The proposed wireless premium was not grounded on the Pelcovits benchmark analysis that underlies SoundExchange's primary rate proposal. Indeed, Dr. Pelcovits specifically declined to do so because of the absence of any data on mobile interactive services. Pelcovits WDT at 60-61. The alternative data offered by Dr. Pelcovits on this issue is not persuasive. Most of the relatively limited data he offers fails to address salient differences between the markets and products represented by that data and the non-interactive webcasting market and its product offerings. In addition, SoundExchange fails to provide any persuasive evidence that a music service delivered to a tethered laptop computer via the Internet is valued differently in the marketplace than the same music service delivered to a laptop computer via the Internet over private or public wireless Internet networks using Wireless Fidelity (“WiFi”) technology. SoundExchange's proposal to exempt wireless transmissions over “personal, short range residential networks” from its proposed wireless premium also underlines its own recognition of the absence of a difference. SoundExchange's Revised Rate Proposal (filed September 29, 2006) at 7. Therefore, on the record before us, we do not find a sufficient basis to support a proposed premium for the wireless transmission of non-interactive webcasts. 36 36 We are also troubled by SoundExchange's proposal to apply the wireless premium even in cases where the service cannot “distinguish between transmissions to wireless devices and fixed line devices.” This proposal is not supported by any evidence that a presumption of “wireless” transmission ought to apply. To the contrary, SoundExchange's own witness, James Griffin admits that, at least in some cases, webcasters simply may not be able to distinguish between transmissions to wireless devices and fixed line devices. Griffin WDT at 32. ii. Determination of Minimum Fee for Commercial Webcasters Under 17 U.S.C. 114(f)(2)(B), the Copyright Royalty Judges are directed to set a minimum fee for each type of service. SoundExchange points out that the Webcaster I CARP noted that one purpose of the minimum fee was to “protect against a situation in which a licensee's performances are such that it costs the license administrator more to administer the license than it would receive in royalties” and another purpose was “to capture the intrinsic value of the licensee's access to the full blanket license, irrespective of whether the service actually transmits any performances.” SoundExchange PFF at ¶ 1349. We find no evidence in the record that establishes an amount for such an “intrinsic value” and, therefore, focus on the administrative cost issue. Here again, we are provided with little evidence of the administrative cost per licensee, 37 especially for a webcaster who may be generating few royalties. The benchmark marketplace agreements generally provide for substantial advance annual minimum fees that are non-refundable, but recoupable against future royalties. As compared to these amounts, SoundExchange's proposal of an annual non-refundable, but recoupable $500 minimum per channel or station payable in advance is a substantially smaller amount. SoundExchange Revised Rate Proposal (filed September 29, 2006). Even though its proposed minimum fee is low, SoundExchange must anticipate that it will cover its administrative costs even in the absence of royalties. Therefore, we find SoundExchange's minimum annual fee proposal is reasonable and applicable to Commercial Webcasters. 38 Moreover, since this flat dollar minimum fee is not adjusted over the term of the license to reflect the impact of inflation, this minimum fee is likely to have a declining financial impact on the costs of the Services over the term of the license. Therefore, we determine that a minimum fee of an annual non-refundable, but recoupable $500 minimum per channel or station 39 payable in advance is reasonable over the term of this license. 37 At the same time, there is evidence that the royalty collection and distribution operations performed by SoundExchange consist of substantial work, such as processing payments and reports of use, matching information received from licensees with information on copyright owners and performers, undertaking related research and quality assurance work, allocating and distributing royalties and resolving errors or disputes. See Kessler WDT at 3-16. 38 Webcaster I found a $500 minimum annual fee per licensee to be reasonable in light of the CARP's reasoning that the RIAA would not have negotiated a minimum fee that failed to cover at least its administrative costs. 67 FR 45262-3 (July 8, 2002). In the agreement to push forward rates and terms in 2003, commercial webcasters and SoundExchange agreed that minimum annual fees would equal $2500, or $500 per channel or station, but in no event less than $500 per licensee. 37 CFR 262.3(d)(2). Again, it is reasonable to anticipate that SoundExchange would not have negotiated a minimum fee that failed to cover at least its administrative costs. 39 This $500 minimum fee is applicable to each individual station and each individual channel, including each individual “side channel” maintained by broadcasters. “Side channels” are channels on the website of a broadcaster that transmit eligible transmissions that are not simultaneously transmitted over-the-air by the broadcaster. Thus, a broadcaster who transmits one simulcast over the Internet and also transmits an eligible transmission over one side channel is subject to a minimum fee of $500 for each respective transmission, for a total in this example of $1,000. In other words, the minimum fee is separately applicable to each side channel. We find no basis in the record for distinguishing between side channels and other stations or channels with respect to a minimum fee that reflects the costs of license administration. We have found, hereinabove, that SoundExchange's proposal of a $500 minimum fee for such administration is clearly reasonable. Further, such administration costs will align more clearly with per station or per channel reports of use where such reports of use are submitted in satisfaction of recordkeeping requirements. 2. Noncommercial Webcasters a. The Willing Buyer/Willing Seller Standard Revisited As previously noted hereinabove, supra at Section IV.A., the Copyright Act requires that the Copyright Royalty Judges establish rates for the section 114 performance license that “most clearly” represent those “that would have been negotiated in the marketplace between a willing buyer and a willing seller.” Both copyright owners and noncommercial services agree that the best approach to determining what rates would apply in such a hypothetical marketplace is to look to comparable marketplace agreements as “benchmarks” indicative of the prices to which willing buyers and willing sellers in this marketplace would agree. However, the copyright owners and the noncommercial services disagree on an appropriate benchmark. The copyright owners insist there is no basis to apply a benchmark other than that used in the commercial market; and consequently, they maintain that the rates supported by the interactive benchmark analysis apply with equal force to Commercial and Noncommercial Webcasters. SoundExchange's Revised Rate Proposal (filed September 29, 2006). The Noncommercial Webcasters, on the other hand, maintain that they are distinguishable from commercial services and, as such, require a different, lower rate. In effect, they claim to be different buyers and, hence, a different benchmark should be consulted. Joint Noncommercial PFF 40 at ¶ 10; Joint Proposed Findings of IBS and WHRB at 9-15. The Noncommercial Webcasters propose lower rates, described supra at Section IV.B.2., based on several alternative benchmarks-(1) the musical works rates applicable to over-the-air broadcasting pursuant to section 118 of the Copyright Act and
(2)rates loosely related to the 2001 NPR-SoundExchange agreement which covered streaming from 1998 to 2004 (SERV-D-X 157). Joint Noncommercial PFF at ¶ 35; NRBNMLC PFF at ¶ 52. 40 The “Joint Noncommercial Proposed Findings of Fact and Conclusions of Law” were submitted by National Public Radio, Corporation For Public Broadcasting-Qualified Stations, the National Religious Broadcasters Noncommercial Music License Committee (“NRBNMLC”), and Collegiate Broadcasters, Inc. Based on the available evidence, we find that, up to a point, certain “noncommercial” webcasters may constitute a distinct segment of the non-interactive webcasting market that in a willing buyer/willing seller hypothetical marketplace would produce different, lower rates than we have determined hereinabove for Commercial Webcasters. A segmented marketplace may have multiple equilibrium prices because it has multiple demand curves for the same commodity relative to a single supply curve. An example of a segmented market is a market for electricity with different prices for commercial users and residential users. In other words, price differentiation or price discrimination is a feature of such markets. The multiple demand curves represent distinct classes of buyers and each demand curve exhibits a different price elasticity of demand. By definition, if the commodity in question derives its demand from its ultimate use, then the marketplace can remain segmented only if buyers are unable to transfer the commodity easily among ultimate uses. Put another way, each type of ultimate use must be different. 41 41 See for example, Burkett, John P., Microeconomics: Optimization, Experiments and Behavior, (Oxford University Press, 2006) at 162 for an introductory microeconomic description of price discrimination. Typically, the submarket characterized by lesser price elasticity will exhibit a higher price. All the economists who testified in this proceeding for both the Services and the copyright owners generally agreed with this description. See, for example, 5/16/06 Tr. 222:19-223:5 (Pelcovits); 11/21/06 Tr. 14:20-15:11 (Brynjolfsson); 11/8/06 Tr. 63:4-64:8 (Jaffe); Picard WRT at 2-7, 11/13/06 Tr. 191:5-196:1 (Picard). For an introductory discussion of price discrimination in copyright markets, see Congressional Budget Office, Copyright Issues in Digital Media, August 2004 at 23-24 or Landes, William M. and Richard A. Posner, the Economic Structure of Intellectual Property Law, (Cambridge, MA: The Belnap Press of the Harvard University Press, 2003) at 374-78, 389-90. Certainly, there is a significant history of Noncommercial Webcasters such as NPR and the copyright owners reaching agreement on rates that were substantially lower than the applicable commercial rates over the corresponding period. See, for example, the 2001 NPR-SoundExchange agreement which covered streaming from 1998 to 2004 (SERV-D-X 157). And, even though SoundExchange offers no formal proposal exempting any Noncommercial Webcasters from its proposed commercial rates, its own economic expert suggests a continuation of differentiated rates where the service offered by such Noncommercial Webcasters does not appear to pose any threat of making serious inroads into the business of those services paying the commercial rate. Brynjolfsson WRT at 42. Dr. Brynjolfsson suggests a cap on listeners beyond which Noncommercial Webcasters would no longer enjoy the lower rate in order to reduce “the chance that small noncommercial stations will cannibalize the webcasting market more generally” and thereby adversely affect the value of the digital performance right in sound recordings. *Id.* SoundExchange does not disavow Dr. Brynjolfsson's testimony on this point, even citing it in its proposed findings of fact. In short, SoundExchange can itself envision circumstances under which a continuation of some regime of differentiated prices would continue. The Copyright Royalty Judges also can envision such circumstances. But, as a matter of pure economic rationale based on the willing buyer/willing seller standard, those circumstances undoubtedly must include safeguards to assure that, as the submarket for noncommercial webcasters that can be distinguished from commercial webcasters evolves, it does not simply converge or overlap with the submarket for commercial webcasters and their indistinguishable noncommercial counterparts. The Copyright Royalty Judges have reached this view after a careful consideration of the characteristics that help to delineate the noncommercial submarket, juxtaposed against evidence in the record that those characteristics may be changing for at least some members of the submarket. For example, the noncommercial broadcasters cite a myriad of characteristics that they claim set them apart from commercial broadcasters. Noncommercial licensees are non-profit organizations. Johnson WDT at ¶ 5; Papish WDT at ¶¶ 4, 12; Robedee WDT at ¶ 2; 6/27/06 Tr. 63:1-21 (Stern); 8/7/06 Tr. 13:11-17, 21:10-12 (Kass). The noncommercial webcasters' mission is to provide educational, cultural, religious and social programming not generally available on commercial venues. See, for example, Stern WDT at 4 and 8/1/06 Tr. 21:11-22:1 (Johnson). Noncommercial webcasters have different sources of funding than ad-supported commercial webcasters-such as listener donations, corporate underwriting or sponsorships, and university funds. Joint Noncommercial PFF at ¶ 20. The implication is that noncommercial webcasters do not compete with commercial webcasters. But as webcasting has developed, some of these traits have become blurred. Public and collegiate radio stations no longer necessarily face a limited geographic audience, but rather their music programming is geographically unbounded so that such stations may compete with commercial webcasters even “worldwide.” SoundExchange PFF at ¶¶ 1105, 1185. Some college radio stations use the Live365 service to stream their simulcasts, making them just another consumer choice available on Live365 together with numerous commercial stations. SoundExchange PFF at ¶ 1186. Commercial Webcasters view Noncommercial Webcasters as competition for an audience interested in listening to music. SoundExchange PFF at ¶ 1116. And some Noncommercial Webcasters, such as NPR, may view Commercial Webcasters as their competition for audience as well. SoundExchange PFF at ¶ 1170. Some noncommercial stations have adopted programming previously found on commercial stations for use on noncommercial side channels or expanding the use of side channels as music outlets. SoundExchange PFF at ¶¶ 1117, 1123. Music programming found on noncommercial stations competes with similar music programming found on commercial stations. SoundExchange PFF at ¶ 1122, SoundExchange RFF at ¶ 284. Sponsorships appear to monetize webcasting in a fashion similar to advertising. SoundExchange PFF at ¶¶ 1130, 1134, 1166. Some noncommercial stations use the functional equivalent of marketing materials that emphasize the size, income and demographics of their audience in much the same manner that commercial stations make their advertising sales pitches. SoundExchange PFF at ¶¶ 1135, 1142. In other words, as webcasting has evolved, some convergence between some noncommercial webcasters and commercial webcasters can be observed ultimately resulting in competition for audience. Brynjolfsson WRT at 40-41. To the extent such competition occurs, market segmentation breaks down, obviating the need for a separate lower royalty rate. b. Proposed Benchmarks and Other Relevant Evidence The copyright owners take the position that the same benchmark applies to the noncommercial and the commercial services in the marketplace. Consequently, they maintain that the rates supported by the interactive benchmark analysis discussed supra at Section IV.C.1.b.i. apply with equal force to Commercial and Noncommercial Webcasters. Because we have found that, up to a point, “noncommercial” webcasters, may constitute a segment of the non-interactive webcasting market that in a willing buyer-willing seller hypothetical marketplace would produce different, lower rates than we have determined hereinabove for Commercial Webcasters, we necessarily find that the benchmark proposed by the copyright owners is applicable to only some Noncommercial Webcasters (i.e., those that cannot be clearly distinguished from their commercial counterparts). In other words, the copyright owners' benchmark does not apply to those Noncommercial Webcasters that can be said to constitute a distinct submarket in the non-interactive marketplace. The interactive market benchmark analysis is based on agreements in which all of the services are Commercial Webcasters. There are no agreements that form part of that analysis that would adequately gauge what a Noncommercial Webcaster in a distinctly different submarket would be willing to pay as a willing buyer for the rights at issue in this proceeding. The Noncommercial Webcasters offer several alternative benchmarks applicable to all noncommercial Services without distinction as well:
(1)The musical works rates applicable to over-the-air broadcasting pursuant to section 118 of the Copyright Act and
(2)rates loosely related to the 2001 NPR-SoundExchange agreement which covered streaming from 1998 to 2004 (SERV-D-X 157). We find neither of these approaches adequately deals with the segmented marketplace. First, the Noncommercial Webcasters would apply the rates determined using their benchmarks to all noncommercial Services, irrespective of whether they were part of a submarket in the marketplace for non-interactive webcasting that was distinctly different from commercial non-interactive webcasting. Second, even within a distinctly different submarket, the benchmarks proposed by the Noncommercial Webcasters suffer from serious flaws. For example, the musical works benchmark proposed by the Services is based on a very different marketplace characterized by different sellers who are selling different rights. Then too, as previously discussed, there is ample evidence in the record from other relevant marketplaces to controvert the underlying premise of this proposed benchmark that the market for sound recordings and the market for musical works are necessarily equivalent. SoundExchange PFF at ¶¶ 483-495. Similarly, the 2001 NPR-SoundExchange agreement covering streaming from 1998 to 2004 does not provide clear evidence of a per station rate that could be viewed as a proxy for one that a willing buyer and a willing seller would negotiate today—it provided for a lump sum amount to cover the entire 74-month term of the contract with no amount specified for different years, and there is nothing in the contract or the record to indicate the parties' expectations as to levels of streaming or the proper attribution of payments for any given year or how additional stations beyond the 410 covered by the agreement were to be handled. Moreover, the transformation of this proposed benchmark by the offering service, the NRBNMLC, into proposed rates adds further problems. In NRBNMLC PFF at ¶ 57, the entire lump sum payable under the 2001 NPR-SoundExchange agreement is divided by 798 stations to arrive at an estimated annual fee of less than $60 per station. But, as previously noted, the agreement in question covered only about half as many stations
(410)and dividing the stated lump sum by 410 stations over the stated 74-month term of the agreement would yield a per station rate twice the amount calculated by NRBNMLC. Furthermore, NRBNMLC's calculation does not add any adjustment for the time value of money in the latter years of the contract 42 nor add any adjustment to account for the erosion in the purchasing power of the dollar since 2004. 43 Finally, none of the final rate proposals 44 of the Noncommercial Webcasters would cover the minimum annual fee determined for Commercial Webcasters. 42 Receiving the 2003 and 2004 fees well in advance of the year earned is more valuable to the recipient because it can be invested and earn interest that would not be available if paid when actually due. 43 Purchasing power loss is complicated by the lack of attribution of amounts to particular years in the contract. Thus, the amount calculated by the NRBNMLC may be, at best, an average for the period. Therefore, a higher amount than that average would be the proper target for adjustment for the erosion in purchasing power since 2004. 44 CBI's final proposed fees ranged from $25 to $175 per station; the NRBNMLC's proposed fees ranged up to $200 per simulcast but with up to two associated channels subsumed within that amount. NPR's proposed fees were $80,000 to cover at least 798 NPR stations (and an undetermined number of CPB stations) or approximately $100 per station. In short, we find neither SoundExchange's proposals based on its benchmark nor the Noncommercial Webcasters' proposals based on their suggested benchmarks adequate to provide a basis for determining the rates to be applicable to that part of the noncommercial market for non-interactive webcasting that can be identified as a distinct submarket from the commercial market. However, we observe that certainly the bare minimum that such services should have to pay is the administrative cost of administering the license. There is no evidence in the record to suggest that the submarket in which a Noncommercial Webcaster may reside would yield a different administrative cost for SoundExchange as compared to the administrative costs associated with Commercial Webcasters and SoundExchange, notably, makes no distinction between webcasters with respect to the $500 minimum fee. Webcaster I affirmed the notion that all webcasters—all Noncommercial Webcasters as well as all Commercial Webcasters—should pay the same minimum fee for the same license. 67 FR 45259 (July 8, 2002). We also find no basis in the record for distinguishing between Commercial Webcasters and Noncommercial Webcasters with respect to the administrative cost of administering the license. 45 Therefore, we determine that a minimum fee of an annual non-refundable, but recoupable $500 minimum per channel or station 46 payable in advance is reasonable over the term of this license. 45 Moreover, even in the musical works benchmark market proposed by some Services such as the NRBNMLC, the minimal amount that a webcaster paid to cover the combined works administered by the three PROs was $636 for college stations in 2006 and $1135 for other public broadcasting entities—that is more than the minimum rate for a single station determined for the section 114 license hereinabove. For a similar analogy, see Webcaster I, 67 FR 45259 (July 8, 2002). 46 This $500 minimum fee is applicable to each individual station and each individual channel, including each individual “side channel” maintained by broadcasters. “Side channels” are channels on the website of a broadcaster that transmit eligible transmissions that are not simultaneously transmitted over-the-air by the broadcaster. Thus, a broadcaster who transmits one simulcast over the Internet and also transmits an eligible transmission over one side channel is subject to a minimum fee of $500 for each respective transmission, for a total in this example of $1,000. In other words, the minimum fee is separately applicable to each side channel. We find no basis in the record for distinguishing between side channels and other stations or channels with respect to a minimum fee that reflects the costs of license administration. We have found, hereinabove, that SoundExchange's proposal of a $500 minimum fee for such administration is clearly reasonable. Further, such administration costs will align more clearly with per station or per channel reports of use where such reports of use are submitted in satisfaction of recordkeeping requirements. Because this minimum fee of $500 is meant to cover administrative costs, it does not address actual usage. Therefore, it would be reasonable to add at least the bare minimum suggested by the Services' proposals as payment for usage to the $500 minimum fee for administration. However, based on the available evidence, we find that past practice has been to treat the minimum fee as recoupable against usage charges. Therefore, we have no basis upon which to add a usage element that is not recoupable to the minimum fee for this distinctive submarket of noncommercial webcasters. Moreover, we note that this minimum fee corresponds to the $500 original fee proposal of IBS and, therefore, demonstrates that, at least for some webcasters in the relevant submarket, the $500 amount represented a ceiling beyond which they would not be willing buyers. Kass WDT at Exhibit A. We turn next to the derivation of a cap to delineate the boundaries of the submarket for which the effective $500 flat fee rate will apply. c. Cap To Delineate Submarket and Rates and Minimum Fees Applicable to the Various Noncommercial Webcasters Because there is evidence in the record that some Noncommercial Webcasters typically have a listenership of less than 20 simultaneous listeners—see, for example 8/2/06 Tr. 137 (Robedee) and 8/2/06 Tr. 243 (Willer)—Dr. Brynjolfsson suggests a cap of 20 simultaneous listeners (or about 14,600 ATH 47 per month) as the boundary for the noncommercial webcasting submarket to be subject to a lower rate. 48 At this level of operation, such a small Noncommercial Webcaster could not be viewed as a serious competitor for commercial enterprises in the webcasting marketplace. We find Dr. Brynjolfsson's suggested line of demarcation too limiting. Size here is only a proxy that aims to capture the characteristics that delineate the noncommercial submarket. See our consideration of these characteristics supra at Section IV.C.2. And, there is evidence in the record that some larger Noncommercial Webcasters, such as the typical NPR station extant in 2004, may also be distinguished from Commercial Webcasters. Indeed, the evidence of convergence in the record appears to apply more clearly to the stations at the larger end of the range of NPR station size. See, for example, SoundExchange PFF at ¶ 1122, SoundExchange RFF at ¶ 284. 47 Aggregate Tuning Hours or ATH refers to the total hours of programming transmitted to all listeners during the relevant time period. Thus, one hour of programming transmitted to 20 simultaneous listeners would produce 20 aggregate tuning hours or 20 ATH. The number of ATH in a month could be calculated by multiplying the average number of simultaneous listeners by the average potential listening hours in a month or 730 (i.e., 365 days in a year multiplied by 24 hours in a day then divided by 12 months). Applying this calculation to an average of 20 simultaneous listeners yields 14,600 ATH per month. 48 In contrast, the original IBS proposal had a cap of 146,000 ATH below which an annual per station rate of $500 would apply. Kass WDT at Exhibit A. The 2001 NPR-SoundExchange agreement covered the typical NPR webcasting station at a rate substantially less than the rate that applied to Commercial Webcasters as of 2004. Based on the available evidence, the typical NPR station in 2004, then, would not have been treated as the functional equivalent of a commercial station. This is significant because the latest available data on what might constitute a typical NPR streaming station consists of a survey of NPR stations undertaken in 2004. See SoundExchange Trial Ex. 67 (NPR Digital Music Rights Station Survey, 2004). According to that survey, the NPR stations averaged 218 simultaneous streaming listeners per station (or the equivalent of 159,140 ATH per month). This average
(218)or a lesser number of listeners was exhibited by 80% of all of the NPR stations engaged in streaming that responded to the survey—in short, it encompassed the experience of all but a handful of NPR stations positioned at the extreme high end of the listenership distribution. 49 See SoundExchange Trial Ex. 67 (NPR Digital Music Rights Station Survey, 2004) at CRB-NPR000036, CRB-NPR000054-57. Therefore, we find that a cap structured to include the typical NPR experience that was viewed by the parties as not being subject to commercial rates, results in a cap of 159,140 ATH per month. 49 The reason the average
(218)or a lesser number encompassed so many stations is that several very large stations at the upper end of the distribution influenced the average. This is statistically apparent from a comparison of the average
(218)with the median number of simultaneous listeners (50). Again, we stress that this cap is only a proxy for assessing the convergence point between Noncommercial Webcasters and Commercial Webcasters in order to delineate a distinct noncommercial submarket in which willing buyers and willing sellers would have a meeting of the minds that would result in a lower rate than the rate applicable to the general commercial webcasting market. 50 Mere size alone, without evidence of the other characteristics that define membership in the noncommercial submarket discussed supra at Section IV.C.2.a., does not make a webcaster eligible for this lower rate. Members of this noncommercial submarket, by definition, are not serious competitors with Commercial Webcasters. 51 50 The Services also advance various public policy considerations which they maintain militate in favor of lower rates. However, the Copyright Act is clear that we are required to apply a willing buyer/willing seller standard in determining rates for all types of participants in the marketplace. We decline to deviate from this standard. We further decline to usurp the authority of Congress to consider potential public policy concerns and, if it chooses, to establish special nonmarket rates for certain noncommercial services. 51 On the other hand, a Commercial Webcaster with an audience of less than 219 simultaneous listeners is, nothwithstanding its size, a direct competitor to other Commercial Webcasters. A careful review of the record also does not persuade us to make any further adjustment to the lower $500 per station rate described hereinabove to account for such considerations as
(1)the promotional or substitution effects on CD sales of webcasting by members of the noncommercial submarket or
(2)the relative contributions made by copyright owners and webcasting services with respect to creativity, technology, capital investment, cost and risk. There is no showing of a quantitative effect of these considerations that is not already embraced within the lower rate we have set. Furthermore, inasmuch as that lower rate is also encompassed by the minimum fee necessary to support administration of the license, no showing has been made by any Noncommercial Webcaster that such administrative costs are somehow overborne by such considerations. Similarly, with respect to the higher rate (i.e., the Commercial Webcaster rate) applicable to Noncommercial Webcasters above the monthly 159,140 ATH cap, we find that no further adjustment is required for the same reasons that we found no such adjustment necessary for Commercial Webcasters subject to the commercial rate we set. See supra at Section IV.C.1.c. In summary, first, we determine that the minimum fee applicable to Noncommercial Webcasters is an annual non-refundable, but recoupable 52 $500 minimum per channel or station payable in advance. In other words, we find no basis for distinguishing between Commercial Webcasters and Noncommercial Webcasters with respect to the minimum fee. See supra at Section IV.C.2.b and Section IV.C.2.c. Second, the following rates apply to Noncommercial Webcasters: 53
(1)an annual per station or per channel rate of $500 for stations or channels will constitute full payment for digital audio transmissions totaling not more than 159,140 ATH per month and
(2)if in any month a Noncommercial Webcaster makes digital audio transmissions in excess of 159,140 ATH per month, then the Noncommercial Webcaster will pay additional usage fees 54 for digital audio transmissions of sound recordings in excess of the cap as follows: a per play rate of $.0008 for 2006, a per play rate of $.0011 for 2007, a per play rate of $.0014 for 2008, a per play rate of $.0018 for 2009 and a per play rate of $.0019 for 2010. 55 As indicated supra at Section IV.C.d.1., we find no basis for making further adjustments to the usage rates to reflect inflation or bundling. 52 In effect, payment of the $500 minimum administrative fee by Noncommercial Webcasters whose monthly ATH is below the cap will satisfy the full royalty obligations of such webcasters because it fully encompasses the per station usage fee. 37 CFR 380.3(b). Therefore, as a practical matter, recoupment does not come into play for such webcasters. 53 Noncommercial Webcasters include such licensees who are eligible nonsubscription transmission services or new subscription services, irrespective of whether they transmit music in large part or in small part. 54 Subject to the credit attributable to any unused balance of the annual minimum fee pursuant to 37 CFR 380.3(b). 55 The Judges recognize that a smooth transition from the prior fee regime to the new fee structure adopted by the Judges hereinabove may be aided by permitting the limited use of an ATH calculation option. Such a transition option enhances the ability of some Services to effectuate speedy payments and, in so doing, improves the ability of copyright owners to more quickly obtain monies due. In short, such a transition measure is reasonably calculated to facilitate a smooth, speedy transition to the new fee structure adopted hereinabove by the Judges. Therefore, the usage fee structure established in this Final Determination will continue use of an ATH option for timely payment of fees due for the years 2006 and 2007. Note: [See table near footnote 55 reference.] The following Aggregate Tuning Hours
(ATH)usage rate calculation options will be available for the transition period of 2006 and 2007: where “Non-Music Programming” is defined as Broadcaster programming reasonably classified as news, talk, sports or business programming; “Broadcast Simulcast Programming” is defined as Broadcaster simulcast programming not reasonably classified as news, talk, sports or business programming; and “Other Programming” is defined as programming other than either Broadcaster simulcast programming or Broadcaster programming reasonably classified as news, talk, sports or business programming. Other programming Broadcast simulcast programming Non-music programming Prior Fees $0.0117 per ATH $0.0088 per ATH $0.0008 per ATH. 2006 $0.0123 per ATH $0.0092 per ATH $0.0011 per ATH. 2007 $0.0169 per ATH $0.0127 per ATH $0.0014 per ATH. Note: See footnote 55 D. The Section 112 Royalty Rates and Minimum Fees 1. Background Section 112(e) of the Copyright Act directs the Copyright Royalty Judges to establish rates and terms for the making of ephemeral copies of digital recordings to enable or facilitate the transmission of those recordings under the statutory license in section 114. As is the case with the section 114 license, we are tasked with setting rates and terms that “most clearly represent the fees that would have been negotiated in the marketplace between a willing buyer and a willing seller,” as well as establish “a minimum fee for each type of service offered by transmitting organizations.” 17 U.S.C. 112(e)(4). The types of “economic, competitive, and programming information” that we are to examine is the same for the section 112 license as it is for the section 114 license. *Id.* Webcaster I set the royalty fee for the section 112 license at 8.8% of the total royalty fee by a Service under the section 114 license. 67 FR 45240, 45262 (July 8, 2002). This fee, as a separate charge, was not part of the 2003 “push forward” of the Webcaster I rates negotiated by SoundExchange and the Services. Rather, the parties agreed to incorporate the fee for section 112 within the rates for section 114 (which increased by a modest $0.000062 per performance over the Webcaster I rates), but the regulations adopting their agreement provided that of the total section 112/114 fee, 8.8% was “deemed” to comprise the charge for ephemeral recordings. 37 CFR 262.3(c). 2. Proposals of the Parties SoundExchange proposes to carry forward the combination of section 112 and 114 rates from the prior license period, including the “deeming” of 8.8% of the total fee owed by Services as constituting the section 112 charge. SoundExchange's Revised Rate Proposal (filed September 29, 2006) at 4. DiMA agrees with this proposal. DiMA RFF at ¶ 115. Radio Broadcasters and the NRBMLC also believe that the fee for the section 112 license should be combined with that for section 114, but oppose the attribution of an 8.8% value for the section 112 license. They argue that the effect is to hide an independent value for the section 112 license within the overall fee even though SoundExchange failed, in their view, to provide any evidence to justify the 8.8% value. Radio Broadcasters “take no position as to the percentage of the overall royalty that is to be designated as the portion attributable to the making of ephemeral copies,” but submit that ephemeral copies have no economic value separate from the value of the performances they effectuate. Radio Broadcasters PFF at ¶ 319. The NRBMLC also contends that ephemeral copies have no independent economic value, citing the Copyright Office's 2001 DMCA Section 104 Report in support. NRBMLC PFF at ¶¶ 60, 62. None of the other parties offer specific proposals as to section 112 rates. SBR Creative Media, Inc. combines section 112 with section 114 in its request for a single fee, while CBI asserts that its stations have no need of the section 112 license. SBR PFF at ¶ 14; CBI PFF at ¶ 19. 3. The Record Evidence While the record in Webcaster I regarding the section 112 license was thin, 56 it is slimmer still in this proceeding. SoundExchange proffers that because copyright owners and performers agreed to include the section 112 charge within the section 114 fee in the 2003 negotiation provided that there was a recognition that section 112 constituted 8.8% of the total value, this is “strong evidence” of what copyright owners and performers believe to be the value of the section 112 license. SoundExchange PFF at ¶ 1370. But see SoundExchange PFF at ¶ 1371 (conceding that “[t]here has been little evidence adduced on the value of ephemeral copies * * *”). SoundExchange further contends that two marketplace agreements—the WMG-Next Radio agreement for a custom radio service and the SONY BMG-MusicMatch custom radio agreement—support its assertion that 8.8% is within the zone of reasonableness. Both of these agreements provide that 10% of the overall fees for streaming are attributable to the making of ephemeral copies. SoundExchange Ex. 002 DR; SoundExchange Ex. 004 DR. 56 See Webcaster I CARP Report at 99-103 (speculating as to the reasons why the parties themselves seemed to attach little importance to the section 112 license). Radio Broadcasters and the NRBMLC counter that none of SoundExchange's witnesses discussed proposed rates or values for ephemeral recordings in written or oral testimony. Instead, they point to testimony of Adam Jaffe offered in Webcaster I that ephemeral copies have no independent economic value from the value of the public performances that they effectuate, Jaffe 2001 WDT at ¶ 82; Jaffe 2001 WRT at 81; 2001 Tr. 6556:10-13 (Jaffe), and offer the Copyright Office's 2001 DMCA Section 104 Report in support of Dr. Jaffe's view. 4. Conclusion Of the thousands of pages of testimony and exhibits submitted by the parties in this proceeding, less than twenty of the pages are devoted to any discussion of the section 112 license and ephemeral copies. It is therefore evident that the parties consider the section 112 license to be of little value at this point in time, which may explain why SoundExchange is content to roll whatever value the license may have into the rates for the section 114 license. Nevertheless, SoundExchange asks the Copyright Royalty Judges to bless its proposal that whatever the royalty fee for the section 114 may be, 8.8% of that fee constitutes the value of the section 112 license. We decline to accept SoundExchange's invitation for two reasons. First, the section 112 license requires us to determine the rate or rates that would have been negotiated between a willing buyer and a willing seller. SoundExchange's valuation of 8.8% is not a rate. Services will not be paying 8.8% more in total royalty fees because of this valuation, nor will they be subtracting 8.8% from their charge if they choose not to avail themselves of the section 112 license. Rather, the 8.8% valuation is nothing more than an effort to preserve a litigation position for future negotiations that the section 112 license has some independent value, as it did in Webcaster I. It is understandable why DiMA would not find the 8.8% figure objectionable since it does not represent any additional charges to its members in this proceeding. Second, the paucity of the record prevents us from determining that 8.8% of the section 114 royalties is either the value of or the rate for the section 112 license. SoundExchange's assertion that its 8.8% proposal is “strong evidence” of copyright owners' and performers' belief as to the appropriate rate applicable to section 112 is bootstrapping. SoundExchange did not present any persuasive testimony or evidence from copyright owners or performers on this point. We also do not find the WMG-Next Radio and the SONY BMG-MusicMatch agreements to be supportive of an 8.8% rate for ephemeral copies, which SoundExchange asserts are evidence of marketplace negotiations and establish a “zone of reasonableness” for section 112 rates in the 10% range. These agreements are for custom radio, which SoundExchange has long avowed is not DMCA compliant, and both have expired. SoundExchange Ex. 002 DR at 10 (WMG-Next Radio Solutions webcasting agreement); SoundExchange Ex. 004 DR at 14 (SONY BMG-MusicMatch Internet radio agreement). More importantly, the 10% figure in both is not a rate but is, like SoundExchange's proposal, a proclamation as to how much of the total fees paid by Next Radio and MusicMatch are attributable to the making of ephemeral copies. Since the 10% figure does not represent any actual monies to be paid by Next Radio or MusicMatch, it can hardly be argued that those agreements are marketplace evidence of negotiated royalty rates for the section 112 license. We are left with a record that demonstrates that, since the expiration of section 112 rates set in Webcaster I, copyright owners and performers are unable to secure separate fees for the section 112 license. The license is merely an add-on to the securing of the performance right granted by the section 114 license. SoundExchange's proposal to include the section 112 license within the rates and minimum fees set for the section 114 license reflects this reality and we accept it. In so doing we decline, for the reasons stated above, to ascribe any particular percentage of the section 114 royalty as representative of the value of the section 112 license. 57 57 We are mindful that section 112(e)(4) prescribes inclusion of a minimum fee for each type of service offered by transmitting organizations. Because we are determining that the section 112 fee is included within the section 114 license fee, we are, likewise, based upon the record evidence, doing the same for the section 112 minimum fee. V. Terms for Royalty Payments Under the Section 112 and 114 Statutory Licenses A. The Statutory Standard Sections 112(e)(3) and 114(f)(2)(A) of the Copyright Act, 17 U.S.C., require the Copyright Royalty Judges to adopt royalty payment terms for the section 112 and 114 statutory licenses. 58 It is established that the standard for setting terms of payment is what the record reflects would have been agreed to by willing buyers and willing sellers in the marketplace. Webcaster I, 67 FR 45240, 45266 (July 8, 2002). It is not established, however, whether the terms adopted must, or should, be administratively feasible or efficient. 58 Consistent with Webcaster I, we are adopting terms for the collection, distribution and administration of royalty payments. In Webcaster I the parties agreed to a set of terms and, with the exception of a few disputed terms, presented them to the CARP for acceptance. In adopting the parties' proposed terms, the CARP declined to make a determination as to whether they were feasible or efficient and deferred to the judgment of the Librarian of Congress. Webcaster I CARP Report at 129. The Librarian declined to address the issue as well and evaluated the agreed-upon terms according to the “arbitrary or contrary to law” standard that the Librarian applied to the other aspects of the CARP's decision. The Librarian did, however, state that he was “skeptical of the proposition that terms negotiated by parties in the context of a CARP proceeding are necessarily evidence of terms that a willing buyer and a willing seller would have negotiated in the marketplace,” and noted that he would not have adopted all of the negotiated terms if his “task were to determine the most reasonable terms governing payment of royalties.” 67 FR 45266 (July 8, 2002). The question therefore remains as to whether the Judges should consider matters of feasability and administrative efficiency in adopting payment terms. We conclude the answer is yes, for two reasons. First, it is an axiom of the copyright laws that statutory licenses are designed to achieve efficiencies that the marketplace cannot. See, H.R. Rep. No. 94-1476, at 89 (1976). Typically, statutory licenses reduce transaction costs associated with licensing large volumes of copyrighted works from multiple rights holders. They guarantee access to the use of prescribed categories of works to those who satisfy the eligibility requirements of a license, while providing a return to the owners of the works subject to the license. Statutory licenses are about administrative efficiency. For example, they increase the speed and ease with which copyrighted works may be used. Adopting a set of terms whose operation is not practical, or creates additional unjustified costs and/or inefficiencies, is inconsistent with the precepts of statutory licensing, and we must avoid such circumstances. Second, we observe that rational willing buyers and sellers themselves will, in their agreements with one another, select terms that are practical, efficient, and avoid excessive costs. Consequently, we have considered the terms presented in agreements offered by the parties to this proceeding, assessed their applicability to the blanket license structure of the statutory licenses, and adopted those terms that will facilitate an efficient collection, distribution and administration of the statutory royalties. B. Collection of Royalties 1. Background Unlike the statutory licenses set forth in sections 111, 119, and chapter 10 of the Copyright Act where royalty payments are submitted directly to a government collecting body (the Licensing Division of the Copyright Office), the section 112 and 114 licenses contain no such provision. Read literally, the licenses appear to require that licensees pay royalties directly to each copyright owner and performer. Recognizing the costs and inefficiencies of such an approach, the parties to the first section 112/114 proceeding negotiated a payment scheme whereby all services paid their royalties to a single “Receiving Agent”: SoundExchange, Inc. See 37 CFR 262.4. SoundExchange was, at that time, an unincorporated division of the Recording Industry Association of America. 59 SoundExchange was then tasked with the responsibility of distributing royalties to those identified in the regulations as “Designated Agents.” By agreement of the parties, both SoundExchange and Royalty Logic, Inc. were identified as “Designated Agents.” The Librarian in Webcaster I reluctantly adopted this payment scheme. 67 FR 45267 n.45 (July 8, 2002). 59 SoundExchange is now an independent entity. SoundExchange PFF at ¶ 72. The royalty collection and distribution scheme adopted in Webcaster I ended with the expiration of the 1998-2002 licensing period. In negotiations for rates and terms for the 2003-2004 licensing period, the parties retained the Receiving Agent/Designated Agent structure but did not recognize Royalty Logic as a Designated Agent. 60 Royalty Logic objected to the parties' agreement and requested the Librarian to convene a CARP on the issue of royalty collection and payment. However, prior to the convening of the CARP, it withdrew from the proceeding. RLI PFF at ¶ 46. Royalty Logic now requests that the Copyright Royalty Judges recognize it in the regulations as both a Designated Agent and a Receiving Agent for the 2006-2010 license period. 60 By the terms of the Copyright Royalty and Distribution Reform Act of 2004, the rates and terms adopted for the 2003-2004 licensing period were extended through the end of 2005. See Copyright Royalty and Distribution Reform Act of 2004, Public Law 108-419, section 6(b)(3) (transition provisions), 118 Stat. 2341, 2370 (2004). 2. Royalty Logic Royalty Logic, acting as an authorized agent for certain copyright owners and performers, 61 is a for-profit subsidiary of Music Reports, Inc. 6/14/06 Tr. 44:21-45:22, 50:20-51:1 (Gertz). 62 Royalty Logic presented the direct testimony of Ronald Gertz, its founder, and the rebuttal testimony of Mr. Gertz and Peter Paterno, Esquire, who represents the recording artists Metallica and Dr. Dre. RLI PFF ¶ 72. 63 61 Despite an invitation from the Copyright Royalty Judges to do so, Royalty Logic was unable to identify all the copyright owners and performers constituting the “RLI Affiliates.” The list appears to include Lester Chambers, North Star Media, Sigala Records, ABKCO Music & Records, Inc., the Everest Record Group, Metallica and Peter, Paul and Mary. 62 MRI is a for-profit company whose principal business is to assist broadcasters in the licensing of musical works used in their programming. 11/15/06 Tr. 103:7-20 (Gertz). 63 Royalty Logic also presented written direct testimony of Lester Chambers, a recording artist. Mr. Chambers, however, did not appear at trial and his testimony therefore was not considered. Royalty Logic contends that it is necessary for the Copyright Royalty Judges to formally recognize it as a “Designated Agent”—complete with direct accounting, reporting, payment and auditing rights vis-a-vis the Services—in the payment regulations to be adopted in this proceeding so that it may compete with SoundExchange as a royalty collection and distribution agent. The claimed need for competition is the central feature of Royalty Logic's presentation. According to Royalty Logic, Designated Agents can compete with one another on multiple levels, including:
(1)The royalty rates to be charged;
(2)interpretations of the statute;
(3)distribution policies; and
(4)costs. 6/14/06, Tr. 101:5-105:5; 124:14-127:20; 314:22-315:19 (Gertz). Royalty Logic advocates a payment scheme whereby a proportionate share of the royalties owed by each Service under the section 112 and 114 licenses would be allocated to each Designated Agent; i.e., it and SoundExchange. Both Designated Agents would be entitled to direct receipt of statements of account, royalty fees and the reports of use of sound recordings required by 37 CFR part 370. For the initial payment period, Royalty Logic proposes that it receive five percent of each Service's royalties, which subsequently would be adjusted either upwards or downwards depending upon the number of performances belonging to Royalty Logic's affiliates that were made by the Service. The identity and ownership of performances (and ephemeral reproductions, if any) would be determined through examination of each Service's report of use of sound recordings. Thereafter, royalty payments to Royalty Logic and SoundExchange would be based solely upon performances of the works of each organization's members, as determined by the reports of use from the prior payment period. Any disputes between the Designated Agents concerning royalty allocations would be resolved by the Copyright Royalty Judges. RLI PFF at ¶ 117(g). 3. SoundExchange SoundExchange is a non-profit performing rights organization that represents thousands of record labels and artists who have specifically authorized SoundExchange to collect royalties on their behalf. Kessler WDT at 3. SoundExchange presented the direct testimony of John Simson, Barrie Kessler, Harold Ray Bradley, and Cathy Finks on the matter of royalty collection and distribution, as well as the rebuttal testimony of Thomas Lee. SoundExchange submits that it would be inefficient for the Copyright Royalty Judges to select more than one agent to receive and distribute royalties. SoundExchange PFF at ¶ 46. It argues that it should be the sole collection and distribution agent because it is proven and well-run and is the most qualified and dedicated to the interests of copyright owners and performers. SoundExchange PFF at ¶¶ 1558-67. It contends that Royalty Logic is unsuitable to serve as an agent because it is owned by Music Reports, Inc., a company that represents licensees of musical works, and such connection creates a conflict of interest. SoundExchange PFF at ¶¶ 50, 51. 4. Receiving Agents and Designated Agents At the outset, the Copyright Royalty Judges must address a fundamental misperception of Royalty Logic, and to a somewhat lesser extent SoundExchange, regarding Receiving Agents and Designated Agents. As noted above, Receiving Agents and Designated Agents and the terms governing their operation were established by agreement by the parties in Webcaster I and were adopted, reluctantly, by the Librarian of Congress. 67 FR 45240, 45266 (July 8, 2002); See also, Determination of Reasonable Rates and Terms for the Digital Performance of Sound Recordings by Preexisting Subscription Services (Final rule), 68 FR 39837, 39839 n.2 (July 3, 2003) (stating that in Webcaster I the Librarian “expressed skepticism about the benefit of the two-tier structure involving a Receiving Agent and more than one Designated Agent, which adds expense and administrative burdens to a process the purpose of which is to make prompt, efficient, and fair payments of royalties to copyright owners and performers with a minimum of expense.”) The entire Receiving Agent/Designated Agent structure is a legal fiction with no basis or grounding in the statute, 64 and we are under no obligation to preserve it, if we determine that there are sound reasons for adopting a different royalty collection and distribution system. 64 Section 114(f)(5)(A) does reference the term “receiving agent.” However, that section of the law, which was created by the Small Webcaster Settlement Act of 2002, Public Law 107-321, 116 Stat. 2780 (2002), is no longer in force. Furthermore, “receiving agent” was defined by reference to § 261.2 of title 37 of the Code of Federal Regulations which are the very same rules adopted in Webcaster I. In evaluating the Receiving Agent/Designated Agent system, we share in the Librarian's skepticism that it is an effective and efficient means of collecting and distributing royalties. The system was pressed in negotiations by the Services in Webcaster I as a means of enabling Royalty Logic to enter the business of collecting and distributing section 112 and 114 royalties even though Royalty Logic did not represent at the time a single copyright owner or performer entitled to those royalties. 68 FR 39839 (July 3, 2003). While Royalty Logic's participation may have presented the Services with a potential future benefit, it is difficult to determine what, if any, benefit was derived by copyright owners and performers. Royalty Logic responds that the benefit to copyright owners and performers is the fruits of competition between it and SoundExchange, yet there is no evidence in the record that demonstrates that any copyright owners or performers sought or claimed such a supposed benefit. If anything, the record reflects that copyright owners and performers prefer SoundExchange as the sole collection and distribution entity. SoundExchange Ex. 239 RP, 240 RP; Lee WRT at 4; Bradley WRT at 20; Fink WDT at 14. We are also troubled by Royalty Logic's contention throughout this proceeding that an agent must be formally recognized by the Copyright Royalty Judges as a Designated Agent before it can have any involvement in the royalty distribution process. This position has no support in the statute. Sections 112(e) and 114(e) state that it is copyright owners and performers who may designate common agents for the receipt of royalties. As the Librarian observed in the 2003 section 112 and 114 preexisting subscription service proceeding: In fact, it is not clear that RLI needs to participate in a CARP proceeding or be named in a negotiated settlement in order to act as a designated agent for purposes of collecting royalty fees on behalf of copyright owners and performers who are entitled to receive funds collected pursuant to the section 112 and section 114 licenses. Section 112(e)(2) and section 114(e) of the Copyright Act both expressly provide that a copyright owner of a sound recording may designate common agents to negotiate, agree to, pay, or receive royalty payments. Under these provisions, it is plausible that a copyright owner or performer could designate any agent of his or her choosing (including RLI)—whether or not that agent had been formally designated in the CARP proceeding—to receive royalties from the licensing of digital transmissions and, by doing so, limit the costs of such agents to those specified in section 114(g)(4), as amended by the Small Webcaster Settlement Act of 2002. 68 FR 39840 n.4 (July 3, 2003). Given our reservations about the Receiving Agent/Designated Agent scheme, and the fact that none of the parties have presented any supporting evidence as to why it must or should continue, the Judges decline to adopt it in this proceeding. Rather, we are adopting a system that effectively and efficiently collects royalties from Services and distributes them to copyright owners, performers, and the agents that they may designate. 5. The Royalty Collective a. The Need for a Single Collective 65 65 A “Collective” is defined in our rules as an organization that is designated by the Copyright Royalty Judges under section 114 to both collect and distribute royalties. 37 CFR 370.5(b)(1). As noted above, a literal reading of the section 112 and 114 licenses suggests that the Services pay directly each and every copyright owner and performer for the use of their respective works. No one in this proceeding, however, has suggested this arrangement, nor do any of the statutory licenses in the Copyright Act function in that fashion. Direct payments would add enormous transaction costs to the Services as they would be forced to locate and make arrangements with all copyright owners and performers for the thousands and thousands of sound recordings they perform, thereby eliminating much, if not all, of the efficiencies achieved by statutory licensing. Consequently, the royalty payment and collection system that we adopt must promote administrative efficiency and economy and reduce transaction costs wherever possible. This stated purpose is wholly consistent with the willing buyer/willing seller standard. In adopting an economically and administratively efficient royalty collection and distribution method, Royalty Logic proposes that we look to the marketplace for performance rights for musical works, which is dominated by three principal rights organizations: ASCAP, BMI and SESAC. These organizations operate on behalf of and are paid for by their members. Royalty Logic contends that competition among the performing rights organizations reduces the administration costs for collecting and distributing royalties in that market and is therefore more efficient than a single Collective such as SoundExchange. We reject application of the performing rights organization model to this proceeding for several reasons. First, the performing rights organizations do not operate exclusively within the confines of a statutory license. The majority of these organizations' activity is direct licensing with users of musical works. 66 While Royalty Logic's argument that multiple Collectives promote competition on pricing may make some sense in the direct licensing context where rates and terms are set through private agreement, it does not make sense where the rates and terms are governed by statutory licenses. 66 The performing rights organizations do collect royalties on behalf of their members for several of the statutory licenses in the Copyright Act. Participation in royalty collection and distribution under these licenses, however, was after they had established their direct licensing businesses. Second, performing rights organizations are member societies that license only the works of their members. The statutory licenses are blanket licenses that cover the works of all copyright owners and performers. Forcing owners and performers to choose membership in one or more Collectives when their works have already been licensed does not seem to serve a purpose and creates a significant practical difficulty in resolving how unaffiliated copyright owners and performers should receive their royalty distributions. Third, while Royalty Logic vehemently argues that competition between it and SoundExchange will reduce the overall administrative costs in the royalty collection and distribution process and therefore result in greater returns for copyright owners and performers, it never presented evidence demonstrating the likelihood of such an outcome. 67 Further, Royalty Logic did not present any evidence showing that its administration costs on a per copyright owner or performer basis will be less than SoundExchange's, merely suggesting that they might be. 6/14/06 Tr. 51:9-14 (Gertz); 11/15/06 Tr. 140:18-21 (Gertz). 67 The small amount of testimony adduced on this point suggests that SoundExchange's administrative costs are lower than those of ASCAP and BMI. Kessler WDT at 16; 6/6/06 Tr. 190:1-4 (Kessler). In sum, we find that selection of a single Collective represents the most economically and administratively efficient system for collecting royalties under the blanket license framework created by the statutory licenses. Transaction costs to the users of such a license are minimized when they can make payment to a single Collective, as opposed to allocating their payments among several. And there is no credible evidence that demonstrates copyright owners and performers suffer increased costs from a system with a single Collective. We now turn to the issue of which of the two parties in this proceeding, Royalty Logic or SoundExchange, will best fulfill the role of the Collective for section 112 and 114 royalties. b. SoundExchange vs. Royalty Logic SoundExchange, a non-profit corporation under 26 U.S.C. 501(c)(6), has operated as the royalty collection and distribution entity since the beginning of the statutory licenses involved in this proceeding, and collects and distributes the royalties paid by preexisting subscription and satellite digital audio services under the statutory license created by the Digital Performance Right in Sound Recordings Act of 1995, Public Law 104-39, 109 Stat. 336 (1995). Kessler WDT at 2. SoundExchange is controlled by an 18-member Board of Directors comprised of equal numbers of representatives of copyright owners and performers. Copyright owners are represented by board members associated with the major record companies (five), independent labels (two), the Recording Industry Association of America (one), and the American Association of Independent Music (one). Performers are represented by one representative each from the American Federation of Television and Radio Artists; the American Federation of Musicians; and seven at-large artist seats. Simson WDT at 33. Though it is a non-member organization, SoundExchange is authorized by over 12,000 performers, 3,000 record labels and 800 record companies to collect royalties on their behalf. SoundExchange PFF at ¶ 75. SoundExchange distributes royalties to nearly 15,000 copyright owner and performer accounts and, as of September 20, 2005, has processed over 650 million sound recording performances. Kessler WDT at 12, 16. It is the only organization that directly receives reports of use from the Services under the licenses in this proceeding. 37 CFR 370.3(d)(4). SoundExchange presented Thomas Lee, President of the American Federation of Musicians, who testified that the structure of SoundExchange's Board provides the necessary checks and balances to ensure that performer interests are well represented. Lee WRT at 4-5. Several performer organizations—the American Federation of Television and Radio Artists, the Music Manager's Forum, and the Recording Artists' Coalition—wrote to Mr. Lee to express their preference and support for SoundExchange in these proceedings. SoundExchange Exs. 239 RP, 240 RP, 241 RP; Lee WRT at 4. Recording artists Harold Ray Bradley and Cathy Fink testified as to their preference for SoundExchange as the sole collective for section 112 and 114 royalties. Bradley WRT at 20; Fink WDT at 14. Royalty Logic, a for-profit corporation, operated as a “Designated Agent” under the Webcaster I decision. Gertz WDT at 5-6; RLI PFF at ¶ 36. Royalty Logic was created and is currently managed by the principals of Music Reports, Inc. Music Reports is in the business of allocating royalty payments from television stations to performing rights societies for musical works performed by those stations. Royalty Logic recently received a significant investment from Abry Partners and may be reorganizing as a result. 11/15/06 Tr. 130:16-131:5 (Gertz). As described in footnote 61, supra, the precise number and identity of copyright owners and performers currently represented by Royalty Logic is unclear. Royalty Logic did not present any copyright owner or performer witnesses 68 in support of its request to be a royalty collection and distribution entity under the section 112 and 114 licenses. It did, however, present the testimony of Peter Paterno, a lawyer representing clients in the music publishing and recording business. Mr. Paterno testified that one of his clients, the rock group Metallica, is affiliated with Royalty Logic and that he has proposed affiliation to three or four other clients. 11/15/06 Tr. 157:10-18; 181:4-22 (Paterno). Royalty Logic also presented as an exhibit a royalty rate agreement between it and DiMA for performances under the statutory licenses, asserting that the agreement demonstrated at least one willing seller's preference for Royalty Logic. RLI PFF at ¶ 61. 68 See, supra, n.63. After considering the presentations of both parties, the Copyright Royalty Judges conclude that SoundExchange is the superior organization to serve as the Collective for the 2006-2010 royalty period. SoundExchange has a proven track record in collecting and processing section 112 and 114 royalties, having done so since the inception of the statutory licenses. Its operational practices appear efficient and fair, and the Judges were not presented with credible evidence of significant failures or deficiencies. 69 Moreover, we are persuaded that the structure and composition of SoundExchange's Board of Directors—with equal representation for copyright owners and performers—provides a greater balance of competing interests than that of Royalty Logic, which is controlled by one person, Mr. Gertz. This was confirmed by the weight of performer testimony on this point which demonstrated a decided preference for the services of SoundExchange over those of Royalty Logic. As the direct beneficiaries of the royalties collected under the statutory licenses, the copyright owner and performer testimony on this point is particularly persuasive. 69 Mr. Gertz and Mr. Paterno did testify as to their awareness of some performers' dissatisfaction with SoundExchange—primarily due to its former ties to the Recording Industry Association of America, Inc.—but the statements were not corroborated by any copyright owner or performer testimony. This testimony is not outweighed by the Royalty Logic/DiMA royalty rate agreement offered by Royalty Logic as evidence of the Services' preference for Royalty Logic. It is difficult to envision any interest that the Services can have in the administration and distribution of royalties, which are the essential functions of the Collective. The Services' views on this subject are not reflected in the agreement. More importantly, the value of the agreement itself is illusory. Signed only by DiMA, a trade organization, it does not bind any Service to its terms; and, to date, no Services have signed on to the agreement. 11/15/06 Tr. 108:7-15 (Gertz). The Copyright Royalty Judges also have serious reservations about the bona fides of Royalty Logic to act as the Collective under the statutory licenses. Royalty Logic “is a for profit organization whose acknowledged goal is to make a profit,” 67 FR 45267 (July 8, 2002), and Mr. Gertz candidly offered that his reasons for seeking entrance into the royalty collection and distribution business was “to make money.” 11/15/06 Tr. 89:7-10 (Gertz). In addition, Mr. Gertz stated that Royalty Logic may decide to pay some copyright owners and/or performers more than others. 11/15/06 Tr. 79:22-80:10 (Gertz). These statements raise a concern as to whether Royalty Logic will act in the best interest of all copyright owners and performers covered by the statutory licenses. The concern is elevated by the fact that Royalty Logic's participation in Webcaster I was championed by the Services and is favored more in this proceeding by the Services than by copyright owners and performers. 70 As noted above, the Services should have little if any interest in the activities of the Collective to whom they pay their royalties (especially where they are relieved of the burden of paying more than one Collective) unless they have reason to believe that Royalty Logic may offer them reduced royalty fees in negotiations for future license periods. Mr. Gertz's business with MRI, which licenses the performance right for musical works on behalf of copyright users rather than owners and performers, suggests this outcome. 71 70 The Copyright Royalty Judges find the testimony of Mr. Paterno an unpersuasive substitute for the views and preferences of copyright owners and performers. Only one of Mr. Paterno's clients, Metallica, has affiliated with Royalty Logic, and he admitted that he has not pressed his other clients to affiliate. 11/15/06 Tr. 157:10-18 (Paterno). Rather, Mr. Paterno stated that he would advocate that clients affiliate with the collective that offered the most money, but he has seemingly made no inquiries on this matter, preferring instead to “see how things play out.” Id. at 157:22-158:10. 71 Our impression on this point is bolstered by the royalty agreement negotiated by Royalty Logic with DiMA, which adopts a rate (to be adjusted to our determination in this proceeding) far below any of the rates proposed by SoundExchange and is almost identical to the proposal of those commercial Services in this proceeding. Likewise, we have no basis in the record to expect that Royalty Logic will deduct lower administration fees, and therefore return greater royalties to copyright owners and performers, than SoundExchange. We were not presented with any comparison of Royalty Logic's and SoundExchange's administration fees, only an argument that competition between Collectives potentially could reduce the overall administration fees. Given that we are selecting only a single Collective, the potential effects of competition on administration fees to be charged to copyright owners and users is not relevant. In sum, the Copyright Royalty Judges determine that SoundExchange will best serve the interests of all copyright owners and performers whose works are subject to the statutory licenses and, therefore, shall be the Collective for the 2006-2010 royalty period. C. Terms Having resolved the matter of who shall serve as the Collective for the 2006-2010 licensing period, the Copyright Royalty Judges now turn to other terms necessary to effectuate payment and distribution. Other than the few disputed terms, adoption of all the terms necessary for payment and distribution presents a decidedly unfortunate challenge, as is discussed below. 1. Webcaster I In Webcaster I, the parties to the proceeding presented the CARP with a comprehensive, negotiated settlement of nearly all the payment, administration and distribution terms for the section 112 and 114 licenses. These terms included governing provisions for submission of payments and statements of account, confidentiality requirements, audit and verification of statements of account and royalty distributions, and unclaimed royalty funds. The CARP was only called upon to resolve two relatively minor disputes regarding terms: whether to include four definitional provisions related to broadcast radio, and what to do with royalties for copyright owners who did not designate either SoundExchange or Royalty Logic to serve as their agent. Applying the willing buyer/willing seller standard, the CARP adopted wholesale the negotiated terms as being the best evidence of marketplace negotiations, chose not to adopt the disputed definitional provisions, and determined that willing buyers and willing sellers would choose SoundExchange for copyright owners who failed to choose a Designated Agent. Webcaster I CARP Report at 128-134. The Librarian made significant alterations to the CARP's determination regarding terms. While he accepted the CARP's rejection of the broadcaster definitional terms and the determination that SoundExchange should serve as agent for unaffiliated copyright owners, he rejected a negotiated term limiting agents' liability for improper distributions and a negotiated term allowing agents to deduct litigation and licensing costs from collected royalty fees. 67 FR 45268-9 (July 8, 2002). He also modified a negotiated definition of “gross proceeds” and created two new definitional provisions: one for “Ephemeral Recordings” and another for “Listener.” Further, he extended the right to select a Designated Agent to performers in addition to copyright owners, granted performers the right to audit their Designated Agent, and “clarified” the negotiated terms for allocating royalty payments among Designated Agents and for allocation of royalties among parties entitled to receive such royalties. 67 FR 45270-1 (July 8, 2002). 2. Negotiated Terms As noted previously, there was no CARP proceeding for the 2003-2004 licensing period. The parties settled their differences and offered the Librarian a negotiated agreement for rates and terms. The proposed agreement included the Webcaster I terms with some modifications. After offering the proposed agreement for public comment, the Librarian adopted it. See, Digital Performance Right in Sound Recordings and Ephemeral Recordings (Final rule), 69 FR 5693 (February 6, 2004). Codified in part 262 of the Copyright Office's regulations, the effective date of these rates and terms was extended by the Copyright Royalty and Distribution Reform Act of 2004 until December 31, 2005, the last day prior to the beginning of the rates and terms established by this proceeding. 37 CFR part 262; Copyright Royalty and Distribution Reform Act of 2004, Public Law 108-419, section 6(b)(3) (transition provisions), 118 Stat. 2341, 2370 (2004). 3. This Proceeding The parties' approach to rates and terms was decidedly different in this proceeding than in Webcaster I. Even though the Copyright Royalty and Distribution Reform Act of 2004 eliminated the CARP system and thereby removed the Librarian and the Copyright Office from further involvement in royalty adjustment proceedings, 72 the parties apparently operated under the assumption that the terms contained in part 262 would remain in place for the 2006-2010 period plus the recommended amendments the Copyright Royalty Judges adopted. The existence of this assumption is confirmed in Part III of the written direct testimony of Barrie Kessler entitled “Modifications Needed to License Terms,” where Ms. Kessler only addresses those terms that she believed required amendment. The Services also refer to the regulations in part 262 as the “current” regulations. See, *e.g.* DiMA and Radio Broadcasters JPFF at ¶ 300. 72 The exception is the limited role of the Register of Copyrights on questions of law. See 17 U.S.C. 802(f)(1)(A)(ii), 802(f)(2)(B)(i), and 802(f)(1)(D). In examining part 262, the Copyright Royalty Judges observe that these are the regulations of the “Copyright Office, Library of Congress.” The Copyright Royalty Judges do not have authority to amend, alter, or otherwise affect these regulations. There is no provision in the Copyright Royalty and Distribution Reform Act of 2004 that carries forward the regulations contained in part 262 or makes them applicable to the Copyright Royalty Judges. 73 Part 262 is therefore not a part of this proceeding. 73 In contrast, 17 U.S.C. 803(b)(6)(B) made the procedural rules of the CARP applicable to the Copyright Royalty Judges until 120 days after appointment of the Copyright Royalty Judges or interim Copyright Royalty Judges who were required to adopt new regulations. Other than testimony and argument devoted to amendment of certain provisions contained in part 262, no other evidence was presented regarding terms for payment and distribution. The Copyright Royalty Judges anticipated that the parties would follow their approach from Webcaster I and present negotiated terms prior to the close of the record. When nothing was forthcoming, the Copyright Royalty Judges issued an order directing parties to file agreed-upon terms no later than the deadline for the submission of their reply findings of fact and conclusions of law. Amendment to Amended Trial Order, Docket No. 2005-1 CRB DTRA (November 28, 2006). When nothing again was filed, the Copyright Royalty Judges questioned counsel at closing arguments who stated that because of the press of time in drafting and filing proposed findings and reply findings, they were unable to discuss or negotiate any terms. Still nothing has been filed. The failure to submit negotiated terms, coupled with the absence of further testimony, places the Copyright Royalty Judges in a difficult situation. While there is sufficient record testimony to resolve the disputed terms, see infra, the only evidence for the “missing terms” is the assumption of the parties that the provisions of part 262, plus our resolution of disputed terms, would constitute the terms for payment and distribution for the 2006-2010 statutory period. The parties' assumption is certainly thin evidence on which to proceed. Nevertheless, there are sufficient grounds to resolve the difficulty of the missing terms. First, we observe that in Webcaster I the Librarian made several wholesale changes to the parties' negotiated terms even though the parties did not propose such changes. The Librarian created definitions for “Ephemeral Recordings” and “Listener” because, in his view, their absence from the regulations would lead to confusion. 67 FR 45269-70 (July 8, 2002). He extended the right of choosing a Designated Agent to performers as well as copyright owners and permitted them to audit Designated Agents because he could “conceive of no reason why Performers should not be given the same choice” as copyright owners. 67 FR 45271 (July 8, 2002). It is clear that the Librarian took these actions so that the regulations governing terms would be clearer, more efficient and fairer to the parties affected. In other words, the Librarian endeavored to make the operation of the statutory licenses as smooth, efficient, and fair as possible. This approach was both necessary and proper and we adopt it here. It is wholly consistent with our conclusion, discussed in Section V.A., supra, that it is our obligation to adopt royalty payment and distribution terms that are practical and efficient. Failure to so act would produce statutory licenses that are operationally chaotic and otherwise unusable, thereby frustrating the Congressional intention underlying their establishment. Second, while an assumption that part 262 would apply to the new license period is not necessarily the best evidence of the required terms, it nevertheless demonstrates the parties' intention to be bound by that provision (including, of course, their proposed changes). They certainly had ample opportunity to disavow this intention and did not do so. Rejection of the provisions contained in part 262 would, in addition to disrupting the operation of the statutory licenses, frustrate the demonstrated intention of the parties. Consequently, the Copyright Royalty Judges are adopting the undisputed provisions of part 262 as the baseline for terms for the 2006-2010 licensing period, subject to the additions and changes adopted in this decision. Parties to future royalty rate proceedings are strongly urged to attach a greater importance to the adoption of terms and to create a more comprehensive and thorough record. 4. Disputed Terms a. Late Payment Fees SoundExchange requests that the Copyright Royalty Judges establish a fee for late payments of statutory royalties equal to 2.5% of the total royalty owed by the Service for that period. The 2.5% late fee represents a substantial increase from the 0.75% late fee adopted in Webcaster I. SoundExchange argues that the increase is necessary. Barrie Kessler stated that many Services are late with their royalty payments and opined that a nominal late fee (0.75%) coupled with the high cost of bringing an infringement action for failure to pay royalties actually encourages late payments. Kessler WDT at 27-28; 6/8/06 Tr. 261:1-6 (Kessler). Ms. Kessler also requested that the late fee be doubled every five days beginning 20 days after SoundExchange sends a Service notification of late payment. Kessler WDT at 28. In support of its request for the 2.5% late fee, SoundExchange offers several marketplace agreements between record companies and services containing, on average, a late payment fee of 1.5% per month, with a high of 2.0%. SoundExchange Ex. 012 DR (UMG-MusicNet subscription services agreement); SoundExchange Ex. 014 DR (UMG-Muze clip license agreement); SoundExchange Ex. 017 DR (UMG-Real Networks subscription agreement); SoundExchange Ex. 021 DR (SONY BMG-Muze clip license agreement); SoundExchange Ex. 002 DR (WMG-Next Radio Solutions webcasting agreement); SoundExchange Ex. 004 DR (SONY BMG-MusicMatch Internet radio agreement). Radio Broadcasters and DiMA counter that a 0.75% late fee (9% per annum) is generous and is greater than the current cost of borrowing. DiMA and Radio Broadcasters JPFF at ¶ 286. They cite the testimony of Eugene Levin of Entercom Broadcasting who, while conceding that Entercom has agreements with a number of suppliers (including ASCAP, BMI and SESAC) that provide for late fees ranging from 12% to 18% per year, testified that late fees are often waived so as to promote a positive business atmosphere and maintain good relations. Levin WRT at 4-5; 11/14/06 Tr. 38:2-9, 41:5-12 (Levin). Radio Broadcasters cite Entercom's agreements with SESAC and Liquid Compass as evidence that late fees can be discretionary. Radio Broadcasters RFF at ¶¶ 137-138. The Copyright Royalty Judges determine that the record evidence does not support continuation of a 0.75% per month late fee. Although Mr. Levin advocated that number, he did not provide a single agreement that his company had for music service that contained such a rate, nor did he state that he was aware of any agreements containing such a rate. To the contrary, Entercom's agreements with ASCAP, BMI and SESAC all provide for late fees ranging from 12% to 18% per annum. 11/14/06 Tr. 38:2-9, 41:5-12 (Levin). The agreements cited by SoundExchange also fall within this range. We are not persuaded that contracting parties' ability to waive late fees requires rejection of a higher late fee. Contract provisions granting discretion to waive late fees were present in some of Entercom's agreements but were noticeably absent from the record company/music service agreements cited by SoundExchange. Mr. Levin was not aware of industry practices with respect to waiver. Moreover, his testimony that waiver promotes good business relationships with contractees is unavailing in the context of statutory licensing. While waiving a late fee can promote good feelings in a private agreement and thereby avoid termination of future goods and services by the offending party, it has no bearing for a statutory license where copyright owners and performers cannot, short of an infringement determination by a federal court, terminate access to their works under the license. After reviewing the record, the Copyright Royalty Judges find that the record company/music service agreements provided by SoundExchange are the best evidence as to the appropriate late fee. While these are not agreements for DMCA-compliant webcasting, 74 there is no reason to believe that a term governing late payment, which is unrelated to the specific royalty rates of the agreements, would be any different in a DMCA-compliant agreement. The agreements establish a range of 1.5% to 2%, with the majority of the agreements containing the 1.5% figure. We adopt the 1.5% figure. 75 In doing so, we reject SoundExchange's request for a doubling of the late fee every five days when a royalty payment is later than 20 days because such a provision does not appear in any of the agreements, and SoundExchange has failed to demonstrate the need for such an extraordinary measure. 74 We acknowledge that the status of whether “custom radio” services are DMCA-compliant remains unresolved, but resolution of this issue is not necessary to our determination. 75 We note that Ms. Kessler testified that a 1.5% late fee, which is the late fee for the section 114 license applicable to preexisting subscription services, still does not discourage late payments. Ms. Kessler did not supply, other than her opinion, evidence to demonstrate that 2.5% is the magic number that will end, or virtually end, future late payments. Further, the Services demonstrated on cross-examination of Ms. Kessler that the frequency of late payments of the Services in this proceeding has not been so rampant as to warrant a much higher late fee. DiMA and Radio Broadcasters JPFF at ¶ 292. b. Statements of Account i. Late Fee for Statements of Account Webcaster I and part 262 of the Copyright Office's rules adopted a late fee for royalty payments but not for late statements of account. Ms. Kessler testified that it is not uncommon for SoundExchange to receive late and incomplete statements of account from Services. 6/6/06 Tr. 137:12-138:20 (Kessler). She urged the Copyright Royalty Judges to adopt a penalty fee for late and/or incomplete statements calculated as if the Service had failed to pay royalties when required. Kessler WDT at 29-30. Mr. Levin testified that it was inappropriate to assess a late fee when a Service did not submit a timely statement of account and particularly unfair where the statement contained good faith errors or omissions. Levin WRT at ¶¶ 16,19; 11/14/06, Tr. 44:18-45:11 (Levin). The Copyright Royalty Judges determine that timely submission of a statement of account is critical to the quick and efficient distribution of royalties. The statement of account identifies the time period to which the royalty payment applies, enables SoundExchange to determine what music service is being paid for and whether the filer has attributed the correct royalty fee to the service or services it is paying for. Although Mr. Levin viewed the timely submission of statements of account as burdensome, we note that the regulations implementing the satellite, cable and digital audio recording devices or media
(DART)statutory licenses require the simultaneous submission of royalty payments and statements of account. See 37 CFR 201.11 (satellite); 37 CFR 201.17 (cable); 37 CFR 201.28 (DART). Failure to timely submit a statement of account with the royalty payment requires payment of a late fee under those licenses. We do not see any unique burdens or circumstances for Services operating under the section 112 and 114 licenses that require a different outcome. Consequently, we adopt the 1.5% per month late fee for statements of account. With respect to the completeness of the statement of account, the burden is upon the Service to provide as complete and error-free a statement as possible. All of the information needed to complete the statement—which is neither complex nor lengthy, see SoundExchange Ex. 212 DP—is in the possession of the Service. Inconsequential good-faith omissions or errors should not warrant imposition of the late fee. ii. Confidentiality There is considerable disagreement as to whether the information contained in statements of account is confidential and should be viewed by the Collective (SoundExchange) alone and not by copyright owners and performers. DiMA and Radio Broadcasters assert that a confidentiality requirement is necessary and is what willing buyers and sellers would agree to in a competitive market. DiMA and Radio Broadcasters JPFF at ¶¶ 297, 299. They cite to the confidentiality provisions of five agreements—SoundExchange Ex. 003 DR sec. 10(b) (WMG-MusicNet subscription services agreement); SoundExchange Ex. 004 DR sec. 10.01 (SONY BMG-MusicMatch Internet radio agreement); SoundExchange Ex. 006 DR sec. 8.1 (EMI standard wholesale agreement for streaming/conditional download licenses); SoundExchange Ex. 017 DR sec. 5(b) (UMG-Real Networks subscription agreement); SoundExchange Ex. 014 DR sec. 6 (WMG-Muze clip license agreement)—in support of this assertion. Further, Mr. Levin testified that the information concerning a Service's total royalty payments, listening minutes and aggregate tuning hours is not the kind of information that Services share with their competitors. 11/14/06 Tr. 47:14-48:7 (Levin). SoundExchange counters that precluding copyright owners and performers from access to the information contained in the statements of account not only impedes the operation of its Board of Directors (which is comprised of owners and performers) but is a denial of the fundamental information necessary for enforcement of the statutory licenses. Kessler WDT at 33. Copyright owners and performers only see statement of account information from prior statutory license periods in the aggregate 76 and cannot make informed decisions to identify and act against Services that, in their view, are not satisfying their statutory requirements. *Id.* at 31. SoundExchange also views the evidence of marketplace activity differently from DiMA and Radio Broadcasters, citing two marketplace agreements between record companies and digital music services that require the reporting of revenues and number of performances so that the copyright owners can verify the calculation of the royalty fee owed under the agreement. SoundExchange Ex. 002 DR (WMG-Next Radio Solutions webcasting license agreement); SoundExchange Ex. 018 DR (UMG-Music Video Net video agreement). Radio Broadcasters counter that even these two agreements have a general confidentiality provision that prevents disclosure to the public of confidential business information. Radio Broadcasters RFF at ¶ 127. 76 See 37 CFR 262.5(c). The Copyright Royalty Judges are troubled by continuing the confidentiality restrictions adopted in Webcaster I and part 262 of the Copyright Office's regulations. Because they were the product of negotiations, there was no finding that the types of information contained in the statements of account were indeed “confidential”; i.e., that their disclosure would harm the business interests of the reporting Services. Mr. Levin, the only witness offered by the Services on this point, did not articulate how the information contained in the statements can or could injure the competitiveness of a Service, or otherwise negatively affect its operation. 11/14/06 Tr. 96:11-104:11 (Levin). Further, he conceded that a competitor's subscription to Arbitron, a broadcasting rating and information service, would provide much of the same information contained in the statements. 11/14/06 Tr. 85:20-87:13, 97:13-99:14 (Levin). The Copyright Royalty Judges come to the conclusion that while Services may want the information contained in statements of account to remain confidential, they have not demonstrated how disclosure of that information is, or is likely to be, harmful. Even more troubling is how the denial of information to copyright owners and performers impacts their substantive rights under the section 112 and 114 licenses. Without the information contained in a statement of account, a copyright owner and/or performer cannot begin to make an informed judgment as to whether a Service is complying with its statutory obligations and making the correct payments. Permitting the disclosure of the information contained in statements of account only to the Collective does not alter this concern and grants the Collective an inordinate amount of control as the only party knowledgeable of the compliance of each of the Services. No support can be found in the statute for an arrangement that effectively imbues only the Collective, or any other agent, with the information necessary to pursue an infringement action. In sum, copyright owners and performers should not be excluded from obtaining the information contained in a statement of account of a Service that performed his or her work. 77 77 This conclusion again is supported by the satellite, cable and DART licenses which permit copyright owners full and complete access to the statements of account of the users of those licenses. Review of the licensing agreements cited by Radio Broadcasters does not counsel a different result. The confidentiality provisions in these agreements generally prohibit disclosure of “business” information to those not party to the agreement, i.e., the public at-large. They do not deny the licensor—the copyright owner—access to this information. And several of the cited agreements permit the licensor to share obtained business information with others, including advisors, financial officers, bankers, and contractors with a need to know. SoundExchange Ex. 004 DR sec. 10.01(a) (SONY BMG-MusicMatch Internet radio agreement); SoundExchange Ex. 002 DR sec. 9.01(a) (WMG-NextRadio Solutions webcasting license agreement). In the statutory licensing setting, copyright owners and performers are the licensors of their works to the Services and certainly need to know the information concerning the Services' payments. Providing the information only to SoundExchange, as the Services request, is not consistent with these agreements. What is consistent with these agreements, however, is a prohibition of disclosure of statement of account information to the general public, and we are adopting that restriction. Therefore, access to statements of account is limited to copyright owners and performers, and their agents and representatives identified in the regulations, whose works were used by a Service under the section 112 and 114 licenses. Copyright owners, performers, and the Collective are directed in the regulations to implement the necessary procedures to guard against access to and dissemination of statement of account information to unauthorized parties. c. Audit and Verification of Payments SoundExchange requests four “clarifications” to the part 262 regulations regarding verification of royalty payments made by the Services:
(1)That the Services should be required to maintain their books and records for the three prior calendar years (January to December) and the entirety of those three years may be audited;
(2)persons other than Certified Public Accountants (“CPAs”) should be allowed to serve as auditors and need only be independent from the Service they are auditing;
(3)individual copyright owners and performers, in addition to the Collective, should be permitted to audit Services; and
(4)the threshold for allocating the costs of an audit should be reduced from a 10% underpayment to a 5% underpayment, or if the Service underpays by $5,000 or more. SoundExchange PFF ¶¶ at 1314, 1342. With the exception of the first request, the Copyright Royalty Judges decline to accept SoundExchange's proposals. By eliminating the requirements that an auditor be a CPA and independent from SoundExchange, SoundExchange is seeking to transform the prior verification process into what it calls “technical audits.” SoundExchange PFF at ¶¶ 1327, 1328. Technical audits would, in SoundExchange's view, reduce its costs by allowing in-house technical experts to conduct the audits rather than outside CPAs, who might lack the technical capability for the data processing and analysis and may be more expensive than in-house personnel. 6/6/06 Tr. 269:16-273:4 (Kessler). The Copyright Royalty Judges have reviewed the record company/music service agreements submitted by the parties and note that some agreements permit technical audits. SoundExchange Ex. 002 DR sec. 5.02 (WMG-NextRadio Solutions webcasting license agreement); SoundExchange Ex. 003 DR sec. 4(b) (WMG-MusicNet subscription services agreement). Others, however, require the auditors to be CPAs, (SoundExchange Ex. 001 DR sec. 4.01 (WMG-All Media Guide clip license agreement), SoundExchange Ex. 014 DR sec. 3.7 (WMG-Muze clip license agreement)), and that the auditor be independent of both the licensor and licensee. SoundExchange Ex. 001 DR sec. 4.01 (WMG-All Media Guide clip license agreement); SoundExchange Ex. 004 DR sec. 6.05 (SONY BMG-MusicMatch Internet radio agreement); SoundExchange Ex. 007 DR sec. 8(b) (EMI—MusicNet nonportable subscription services agreement). While technical audits by in-house personnel might be cheaper for the Collective, we conclude that it is more important, in the interest of establishing a high level of credibility in the results of the audit, that the auditor be independent of both parties. 11/14/06 Tr. 9:8-11:11 (Levin). Likewise, we find that requiring the auditor to be certified further raises confidence levels in the audit. CPAs have experience in the field of accounting, are familiar with the accepted standards and practices for auditing, and are governed by standards of conduct. If technical skills are required to process the data of a Service, the auditor can request assistance. In sum, the Copyright Royalty Judges are requiring that the auditor be certified and independent of both SoundExchange and the Service being audited. The Copyright Royalty Judges are not persuaded that all copyright owners and performers should have the right to audit a Service. It is one thing for a Service that enters into a private agreement with a copyright owner to allow the owner to conduct an audit. Kenswil WDT at 10-11; Eisenberg WDT at 13. It is an altogether different matter to grant the right of audit to copyright owners and performers under a statutory licensing scheme where there is no privity of contract and the potential for a significant magnitude of audits. We agree with the Services that subjecting them to that kind of extensive auditing process could seriously impair their business operations. Levin WRT at ¶ 30. Likewise, we are not persuaded that the underpayment threshold for shifting the cost of an audit should be reduced from an underpayment of 10% to one of 5% of the royalty fee due, or $5,000, whichever is less. Ms. Kessler stated that the 10% figure was too high and encourages the Services to deliberately underpay their royalties up to 9%, but she did not offer any direct evidence of this occurring. Furthermore, the 10% figure is consistent with several of the record company/music service agreements. SoundExchange Ex. 003 DR sec. 6(f) (WMG-MusicNet subscription services agreement); SoundExchange Ex. 004 DR sec. 6.06 (SONY BMG-MusicMatch Internet radio agreement); SoundExchange 010 DR sec. 5(c) (EMI-Muze clip license agreement). Finally, the Copyright Royalty Judges agree with SoundExchange that the Services should retain their books and records for the three calendar years prior to the current year. Services need to know with precision how long they must retain their books and records as well as the time period that is potentially subject to an audit. d. Other Matters i. Recordkeeping Subsequent to the conclusion of the hearings on the direct statements, the Copyright Royalty Judges issued an Interim Final Rule in Docket No. RM 2005-2, the docket establishing notice and recordkeeping requirements for certain digital audio services using the section 112 and 114 licenses. Notice and Recordkeeping for Use of Sound Recordings Under Statutory License (Interim final rule), 71 FR 59010 (October 6, 2006). The Interim Final Rule prescribed the format and delivery requirements for reports of use of sound recordings, thereby completing the interim recordkeeping rulemaking process begun several years ago by the Copyright Office. Several of the parties in this proceeding, uncertain as to whether such recordkeeping issues would be addressed in this docket and noting the statutory language that permits the Copyright Royalty Judges to modify their existing recordkeeping rules, 17 U.S.C. 803(c)(3), submitted testimony on the matter. Although we ruled that recordkeeping matters would be addressed through notice and comment rulemaking and not in this proceeding, we did not strike the testimony. Instead, such testimony was allowed to remain in the record as evidence, if any, of the relative costs to the Services and the Collective associated with recordkeeping. Order Denying Radio Broadcasters' Motion for Clarification, Motion to Strike SoundExchange Exhibits 414-418 DP and Motion to Set Expedited Briefing Schedule, Docket No. 2005-1 CRB DTRA (September 8, 2006). The costs of recordkeeping to both sides did not influence our determination of royalty rates in this proceeding, nor are we choosing to amend our existing recordkeeping regulations. See 37 CFR part 370. The testimony presented by the Services as to the costs associated with recordkeeping was vague and unsubstantiated and went little beyond the assertion that there are some costs associated with recordkeeping. Clearly, any recordkeeping, no matter how modest, involves some costs. Nevertheless, the statute does require reporting. 17 U.S.C. 112(e)(4), 114(f)(4)(A). And despite the fact that most of the requirements for creating a report of use have been public since 2002, see Notice and Recordkeeping for Use of Sound Recordings Under Statutory Licenses (Notice requesting written proposals and announcement of status conference), 67 FR 59573 (September 23, 2002), the Services failed to quantify either the magnitude of the actual overall costs or the average costs to individual Services. In any event, because our recordkeeping regulations are interim and not final, there is ample opportunity to again address the Services' costs in a future rulemaking. The ability to influence and adjust the costs of recordkeeping is far more direct in that context than this rate determination proceeding and is more properly handled there. Likewise, there was no persuasive testimony compelling an adjustment of the current recordkeeping regulations. SoundExchange presses for census reporting, but the record is incomplete as to effectiveness of the current periodic reporting requirement. Once again, the Copyright Royalty Judges conclude that this matter is more appropriate for a future recordkeeping rulemaking. ii. Royalty Distribution Having eschewed the Receiving Agent/Designated Agent model of the prior regulations in favor of a single Collective, we are adopting streamlined royalty distribution procedures. SoundExchange has the responsibility of collecting the royalties from the Services and distributing them to all eligible copyright owners and performers, including any agents designated by copyright owners and/or performers for their receipt. Deduction of costs by SoundExchange is governed by the statute, 17 U.S.C. 114(g)(3), and therefore we have no authority to address any resulting inequalities. With respect to the distribution methodology, the Copyright Royalty Judges are retaining the requirement that all performances be valued equally by the Collective. SoundExchange is already familiar with and applies this requirement. 6/6/06 Tr. 171:2-172:10 (Kessler). Copyright owners and/or performers are certainly free to agree to subsequent distribution methodologies once they have received their distribution from the Collective. VI. Determination and Order Having fully considered the record, the Copyright Royalty Judges make the above Findings of Fact based on the record. Relying upon these Findings of Fact, the Copyright Royalty Judges unanimously adopt every portion of this Final Determination of the Rates and Terms of the Statutory Licenses for the digital audio transmission of sound recordings, pursuant to 17 U.S.C. 114, and for the making of ephemeral phonorecords, pursuant to 17 U.S.C. 112(e). The Copyright Royalty Judges exercise their authority under 17 U.S.C. 803(c), and transmit this Final Determination to the Librarian of Congress for publication in the **Federal Register** , pursuant to 17 U.S.C. 803(c)(6). So Ordered. James Scott Sledge, *Chief Copyright Royalty Judge.* William J. Roberts, *Copyright Royalty Judge.* Stanley C. Wisniewski, *Copyright Royalty Judge.* Dated: April 23, 2007. List of Subjects in 37 CFR Part 380 Copyright, Sound recordings. Final Regulation For the reasons set forth in the preamble, Chapter III of Title 37 of the Code of Federal Regulations is amended by adding new Subchapter E to read as follows: Subchapter E—Rates and Terms for Statutory Licenses PART 380—RATES AND TERMS FOR CERTAIN ELIGIBLE NONSUBSCRIPTION TRANSMISSIONS, NEW SUBSCRIPTION SERVICES AND THE MAKING OF EPHEMERAL REPRODUCTIONS Sec. 380.1 General. 380.2 Definitions. 380.3 Royalty fees for the public performance of sound recordings and for ephemeral recordings. 380.4 Terms for making payment of royalty fees and statements of account. 380.5 Confidential information. 380.6 Verification of royalty payments. 380.7 Verification of royalty distributions. 380.8 Unclaimed funds. Authority: 17 U.S.C. 112(e), 114(f), 804(b)(3). § 380.1 General.
(a)*Scope.* This part 380 establishes rates and terms of royalty payments for the public performance of sound recordings in certain digital transmissions by Licensees in accordance with the provisions of 17 U.S.C. 114, and the making of Ephemeral Recordings by Licensees in accordance with the provisions of 17 U.S.C. 112(e), during the period January 1, 2006, through December 31, 2010.
(b)*Legal compliance.* Licensees relying upon the statutory licenses set forth in 17 U.S.C. 112 and 114 shall comply with the requirements of those sections, the rates and terms of this part, and any other applicable regulations.
(c)*Relationship to voluntary agreements.* Notwithstanding the royalty rates and terms established in this part, the rates and terms of any license agreements entered into by Copyright Owners and digital audio services shall apply in lieu of the rates and terms of this part to transmission within the scope of such agreements. § 380.2 Definitions. For purposes of this part, the following definitions shall apply:
(a)*Aggregate Tuning Hours*
(ATH)means the total hours of programming that the Licensee has transmitted during the relevant period to all Listeners within the United States from all channels and stations that provide audio programming consisting, in whole or in part, of eligible nonsubscription transmissions or noninteractive digital audio transmissions as part of a new subscription service, less the actual running time of any sound recordings for which the Licensee has obtained direct licenses apart from 17 U.S.C. 114(d)(2) or which do not require a license under United States copyright law. By way of example, if a service transmitted one hour of programming to 10 simultaneous Listeners, the service's Aggregate Tuning Hours would equal 10. If 3 minutes of that hour consisted of transmission of a directly licensed recording, the service's Aggregate Tuning Hours would equal 9 hours and 30 minutes. As an additional example, if one Listener listened to a service for 10 hours (and none of the recordings transmitted during that time was directly licensed), the service's Aggregate Tuning Hours would equal 10.
(b)*Broadcaster* is a type of Commercial Webcaster or Noncommercial Webcaster that owns and operates a terrestial AM or FM radio station that is licensed by the Federal Communications Commission.
(c)*Collective* is the collection and distribution organization that is designated by the Copyright Royalty Judges. For the 2006-2010 license period, the Collective is SoundExchange, Inc.
(d)*Commercial Webcaster* is a Licensee, other than a Noncommercial Webcaster, that makes eligible digital audio transmissions.
(e)*Copyright Owners* are sound recording copyright owners who are entitled to royalty payments made under this part pursuant to the statutory licenses under 17 U.S.C. 112(e) and 114(f).
(f)*Ephemeral Recording* is a phonorecord created for the purpose of facilitating a transmission of a public performance of a sound recording under a statutory license in accordance with 17 U.S.C. 114(f), and subject to the limitations specified in 17 U.S.C.112(e).
(g)*Licensee* is a person that has obtained a statutory license under 17 U.S.C. 114, and the implementing regulations, to make eligible nonsubscription transmissions, or noninteractive digital audio transmissions as part of a new subscription service (as defined in 17 U.S.C. 114(j)(8)), or that has obtained a statutory license under 17 U.S.C. 112(e), and the implementing regulations, to make Ephemeral Recordings for use in facilitating such transmissions.
(h)*Noncommercial Webcaster* is a Licensee that makes eligible digital audio transmissions and:
(1)Is exempt from taxation under section 501 of the Internal Revenue Code of 1986 (26 U.S.C. 501),
(2)Has applied in good faith to the Internal Revenue Service for exemption from taxation under section 501 of the Internal Revenue Code and has a commercially reasonable expectation that such exemption shall be granted, or
(3)Is operated by a State or possession or any governmental entity or subordinate thereof, or by the United States or District of Columbia, for exclusively public purposes.
(i)*Performance* is each instance in which any portion of a sound recording is publicly performed to a Listener by means of a digital audio transmission (e.g., the delivery of any portion of a single track from a compact disc to one Listener) but excluding the following:
(1)A performance of a sound recording that does not require a license (e.g., a sound recording that is not copyrighted);
(2)A performance of a sound recording for which the service has previously obtained a license from the Copyright Owner of such sound recording; and
(3)An incidental performance that both:
(i)Makes no more than incidental use of sound recordings including, but not limited to, brief musical transitions in and out of commercials or program segments, brief performances during news, talk and sports programming, brief background performances during disk jockey announcements, brief performances during commercials of sixty seconds or less in duration, or brief performances during sporting or other public events and
(ii)Other than ambient music that is background at a public event, does not contain an entire sound recording and does not feature a particular sound recording of more than thirty seconds (as in the case of a sound recording used as a theme song).
(j)*Performers* means the independent administrators identified in 17 U.S.C. 114(g)(2)(B) and
(C)and the parties identified in 17 U.S.C. 114(g)(2)(D).
(k)*Qualified Auditor* is a Certified Public Accountant.
(l)*Side Channel* is a channel on the website of a broadcaster which channel transmits eligible transmissions that are not simultaneously transmitted over the air by the broadcaster. § 380.3 Royalty fees for the public performance of sound recordings and for ephemeral recordings.
(a)Royalty rates and fees for eligible digital transmissions of sound recordings made pursuant to 17 U.S.C. 114, and the making of ephemeral recordings pursuant to 17 U.S.C. 112 are as follows:
(1)*Commercial Webcasters:*
(i)The per-performance fee for 2006-2010: For all digital audio transmissions, including simultaneous digital audio retransmissions of over-the-air AM or FM radio broadcasts, a Commercial Webcaster will pay a performance royalty of: $.0008 per performance for 2006, $.0011 per performance for 2007, $.0014 per performance for 2008, $.0018 per performance for 2009, and $.0019 per performance for 2010. The royalty payable under 17 U.S.C. 112 for any reproduction of a phonorecord made by a Commercial Webcaster during this license period and used solely by the Commercial Webcaster to facilitate transmissions for which it pays royalties as and when provided in this section is deemed to be included within such royalty payments.
(ii)Optional transitional Aggregate Tuning Hour fee for 2006-2007: The following Aggregate Tuning Hours
(ATH)usage rate calculation options, in lieu of the per-performance fee, are available for the transition period of 2006 and 2007: Other programming Broadcast simulcast programming Non-music programming Prior Fees $0.0117 per ATH $0.0088 per ATH $0.0008 per ATH. 2006 $0.0123 per ATH $0.0092 per ATH $0.0011 per ATH. 2007 $0.0169 per ATH $0.0127 per ATH $0.0014 per ATH.
(iii)“Non-Music Programming” is defined as Broadcaster programming reasonably classified as news, talk, sports or business programming; “Broadcast Simulcast Programming” is defined as Broadcaster simulcast programming not reasonably classified as news, talk, sports or business programming; and “Other Programming” is defined as programming other than either Broadcaster simulcast programming or Broadcaster programming reasonably classified as news, talk, sports or business programming.
(2)*Noncommercial Webcasters:*
(i)For all digital audio transmissions totaling not more than 159,140 Aggregate Tuning Hours
(ATH)in a month, including simultaneous digital audio retransmissions of over-the-air AM or FM radio broadcasts, a Noncommercial Webcaster will pay an annual per channel or per station performance royalty of $500 in 2006, 2007, 2008, 2009 and 2010.
(ii)For all digital audio transmissions totaling in excess of 159,140 Aggregate Tuning Hours
(ATH)in a month, including simultaneous digital audio retransmissions of over-the-air AM or FM radio broadcasts, a Noncommercial Webcaster will pay a performance royalty of: $.0008 per performance for 2006, $.0011 per performance for 2007, $.0014 per performance for 2008, $.0018 per performance for 2009, and $.0019 per performance for 2010.
(iii)The following Aggregate Tuning Hours
(ATH)usage rate calculation options, in lieu of the per-performance fee, are available for the transition period of 2006 and 2007: Other programming Broadcast simulcast programming Non-music programming Prior Fees $0.0117 per ATH $0.0088 per ATH $0.0008 per ATH. 2006 $0.0123 per ATH $0.0092 per ATH $0.0011 per ATH. 2007 $0.0169 per ATH $0.0127 per ATH $0.0014 per ATH.
(iv)“Non-Music Programming” is defined as Broadcaster programming reasonably classified as news, talk, sports or business programming; “Broadcast Simulcast Programming” is defined as Broadcaster simulcast programming not reasonably classified as news, talk, sports or business programming; and “Other Programming” is defined as programming other than either Broadcaster simulcast programming or Broadcaster programming reasonably classified as news, talk, sports or business programming.
(v)The royalty payable under 17 U.S.C. 112 for any reproduction of a phonorecord made by a Noncommercial Webcaster during this license period and used solely by the Noncommercial Webcaster to facilitate transmissions for which it pays royalties as and when provided in this section is deemed to be included within such royalty payments.
(b)*Minimum fee.* Each Commercial Webcaster and Noncommercial Webcaster will pay an annual, nonrefundable minimum fee of $500 for each calendar year or part of a calendar year of the license period during which they are Licensees pursuant to licenses under 17 U.S.C. 114. This annual minimum fee is payable for each individual channel and each individual station maintained by Commercial Webcasters and Noncommercial Webcasters and is also payable for each individual Side Channel maintained by Broadcasters who are Licensees. The minimum fee payable under 17 U.S.C. 112 is deemed to be included within the minimum fee payable under 17 U.S.C. 114. Upon payment of the minimum fee, the Licensee will receive a credit in the amount of the minimum fee against any additional royalty fees payable in the same calendar year. § 380.4 Terms for making payment of royalty fees and statements of account.
(a)*Payment to the Collective.* A Licensee shall make the royalty payments due under § 380.3 to the Collective.
(b)*Designation of the Collective.*
(1)Until such time as a new designation is made, SoundExchange, Inc., is designated as the Collective to receive statements of account and royalty payments from Licensees due under § 380.3 and to distribute such royalty payments to each Copyright Owner and Performer, or their designated agents, entitled to receive royalties under 17 U.S.C. 112(e) or 114(g).
(2)If SoundExchange, Inc. should dissolve or cease to be governed by a board consisting of equal numbers of representatives of Copyright Owners and Performers, then it shall be replaced by a successor Collective upon the fulfillment of the requirements set forth in paragraph (b)(2)(i) of this section.
(i)By a majority vote of the nine Copyright Owner representatives and the nine Performer representatives on the SoundExchange board as of the last day preceding the condition precedent in paragraph (b)(2) of this section, such representatives shall file a petition with the Copyright Royalty Board designating a successor to collect and distribute royalty payments to Copyright Owners and Performers entitled to receive royalties under 17 U.S.C. 112(e) or 114(g) that have themselves authorized such Collective.
(ii)The Copyright Royalty Judges shall publish in the **Federal Register** within 30 days of receipt of a petition filed under paragraph (b)(2)(i) of this section an order designating the Collective named in such petition.
(c)*Monthly payments.* A Licensee shall make any payments due under § 380.3 by the 45th day after the end of each month for that month, except that payments due under § 380.3 for the period beginning January 1, 2006, through the last day of the month in which the Copyright Royalty Judges issue their final determination adopting these rates and terms shall be due 45 days after the end of such period. All monthly payments shall be rounded to the nearest cent.
(d)*Minimum payments.* A Licensee shall make any minimum payment due under § 380.3(b) by January 31 of the applicable calendar year, except that:
(1)Payment due under § 380.3(b) for 2006 and 2007 shall be due 45 days after the last day of the month in which the Copyright Royalty Judges issue their final determination adopting these rates and terms.
(2)Payment for a Licensee that has not previously made eligible nonsubscription transmissions, noninteractive digital audio transmissions as part of a new subscription service or Ephemeral Recordings pursuant to the licenses in 17 U.S.C. 114 and/or 17 U.S.C. 112(e) shall be due by the 45th day after the end of the month in which the Licensee commences to do so.
(e)*Late payments and statements of account.* A Licensee shall pay a late fee of 1.5% per month, or the highest lawful rate, whichever is lower, for any payment and/or statement of account received by the Collective after the due date. Late fees shall accrue from the due date until payment is received by the Collective.
(f)*Statements of account.* Any payment due under § 380.3 shall be accompanied by a corresponding statement of account. A statement of account shall contain the following information:
(1)Such information as is necessary to calculate the accompanying royalty payment;
(2)The name, address, business title, telephone number, facsimile number (if any), electronic mail address and other contact information of the person to be contacted for information or questions concerning the content of the statement of account;
(3)The handwritten signature of:
(i)The owner of the Licensee or a duly authorized agent of the owner, if the Licensee is not a partnership or corporation;
(ii)A partner or delegee, if the Licensee is a partnership; or
(iii)An officer of the corporation, if the Licensee is a corporation.
(4)The printed or typewritten name of the person signing the statement of account;
(5)The date of signature;
(6)If the Licensee is a partnership or corporation, the title or official position held in the partnership or corporation by the person signing the statement of account;
(7)A certification of the capacity of the person signing; and
(8)A statement to the following effect: I, the undersigned owner or agent of the Licensee, or officer or partner, have examined this statement of account and hereby state that it is true, accurate, and complete to my knowledge after reasonable due diligence.
(g)*Distribution of royalties.*
(1)The Collective shall promptly distribute royalties received from Licensees to Copyright Owners and Performers, or their designated agents, that are entitled to such royalties. The Collective shall only be responsible for making distributions to those Copyright Owners, Performers, or their designated agents who provide the Collective with such information as is necessary to identify the correct recipient. The Collective shall distribute royalties on a basis that values all performances by a Licensee equally based upon the information provided under the reports of use requirements for Licensees contained in § 370.3 of this chapter.
(2)If the Collective is unable to locate a Copyright Owner or Performer entitled to a distribution of royalties under paragraph (g)(1) of this section within 3 years from the date of payment by a Licensee, such distribution may first be applied to the costs directly attributable to the administration of that distribution. The foregoing shall apply notwithstanding the common law or statutes of any State.
(h)*Retention of records.* Books and records of a Licensee and of the Collective relating to payments of and distributions of royalties shall be kept for a period of not less than the prior 3 calendar years. § 380.5 Confidential information.
(a)*Definition.* For purposes of this part, “Confidential Information” shall include the statements of account and any information contained therein, including the amount of royalty payments, and any information pertaining to the statements of account reasonably designated as confidential by the Licensee submitting the statement.
(b)*Exclusion.* Confidential Information shall not include documents or information that at the time of delivery to the Collective are public knowledge. The party claiming the benefit of this provision shall have the burden of proving that the disclosed information was public knowledge.
(c)*Use of Confidential Information.* In no event shall the Collective use any Confidential Information for any purpose other than royalty collection and distribution and activities related directly thereto.
(d)*Disclosure of Confidential Information.* Access to Confidential Information shall be limited to:
(1)Those employees, agents, attorneys, consultants and independent contractors of the Collective, subject to an appropriate confidentiality agreement, who are engaged in the collection and distribution of royalty payments hereunder and activities related thereto, for the purpose of performing such duties during the ordinary course of their work and who require access to the Confidential Information;
(2)An independent and Qualified Auditor, subject to an appropriate confidentiality agreement, who is authorized to act on behalf of the Collective with respect to verification of a Licensee's statement of account pursuant to § 380.6 or on behalf of a Copyright Owner or Performer with respect to the verification of royalty distributions pursuant to § 380.7;
(3)Copyright Owners and Performers, including their designated agents, whose works have been used under the statutory licenses set forth in 17 U.S.C. 112(e) and 114(f) by the Licensee whose Confidential Information is being supplied, subject to an appropriate confidentiality agreement, and including those employees, agents, attorneys, consultants and independent contractors of such Copyright Owners and Performers and their designated agents, subject to an appropriate confidentiality agreement, for the purpose of performing their duties during the ordinary course of their work and who require access to the Confidential Information; and
(4)In connection with future proceedings under 17 U.S.C. 112(e) and 114(f) before the Copyright Royalty Judges, and under an appropriate protective order, attorneys, consultants and other authorized agents of the parties to the proceedings or the courts.
(e)*Safeguarding of Confidential Information.* The Collective and any person identified in paragraph
(d)of this section shall implement procedures to safeguard against unauthorized access to or dissemination of any Confidential Information using a reasonable standard of care, but no less than the same degree of security used to protect Confidential Information or similarly sensitive information belonging to the Collective or person. § 380.6 Verification of royalty payments.
(a)*General.* This section prescribes procedures by which the Collective may verify the royalty payments made by a Licensee.
(b)*Frequency of verification.* The Collective may conduct a single audit of a Licensee, upon reasonable notice and during reasonable business hours, during any given calendar year, for any or all of the prior 3 calendar years, but no calendar year shall be subject to audit more than once.
(c)*Notice of intent to audit.* The Collective must file with the Copyright Royalty Board a notice of intent to audit a particular Licensee, which shall, within 30 days of the filing of the notice, publish in the **Federal Register** a notice announcing such filing. The notification of intent to audit shall be served at the same time on the Licensee to be audited. Any such audit shall be conducted by an independent and Qualified Auditor identified in the notice, and shall be binding on all parties.
(d)*Acquisition and retention of report.* The Licensee shall use commercially reasonable efforts to obtain or to provide access to any relevant books and records maintained by third parties for the purpose of the audit. The Collective shall retain the report of the verification for a period of not less than 3 years.
(e)*Acceptable verification procedure.* An audit, including underlying paperwork, which was performed in the ordinary course of business according to generally accepted auditing standards by an independent and Qualified Auditor, shall serve as an acceptable verification procedure for all parties with respect to the information that is within the scope of the audit.
(f)*Consultation.* Before rendering a written report to the Collective, except where the auditor has a reasonable basis to suspect fraud and disclosure would, in the reasonable opinion of the auditor, prejudice the investigation of such suspected fraud, the auditor shall review the tentative written findings of the audit with the appropriate agent or employee of the Licensee being audited in order to remedy any factual errors and clarify any issues relating to the audit; Provided that an appropriate agent or employee of the Licensee reasonably cooperates with the auditor to remedy promptly any factual errors or clarify any issues raised by the audit.
(g)*Costs of the verification procedure.* The Collective shall pay the cost of the verification procedure, unless it is finally determined that there was an underpayment of 10% or more, in which case the Licensee shall, in addition to paying the amount of any underpayment, bear the reasonable costs of the verification procedure. § 380.7 Verification of royalty distributions.
(a)*General.* This section prescribes procedures by which any Copyright Owner or Performer may verify the royalty distributions made by the Collective; Provided, however, that nothing contained in this section shall apply to situations where a Copyright Owner or Performer and the Collective have agreed as to proper verification methods.
(b)*Frequency of verification.* A Copyright Owner or Performer may conduct a single audit of the Collective upon reasonable notice and during reasonable business hours, during any given calendar year, for any or all of the prior 3 calendar years, but no calendar year shall be subject to audit more than once.
(c)*Notice of intent to audit.* A Copyright Owner or Performer must file with the Copyright Royalty Board a notice of intent to audit the Collective, which shall, within 30 days of the filing of the notice, publish in the **Federal Register** a notice announcing such filing. The notification of intent to audit shall be served at the same time on the Collective. Any audit shall be conducted by an independent and Qualified Auditor identified in the notice, and shall be binding on all Copyright Owners and Performers.
(d)*Acquisition and retention of report.* The Collective shall use commercially reasonable efforts to obtain or to provide access to any relevant books and records maintained by third parties for the purpose of the audit. The Copyright Owner or Performer requesting the verification procedure shall retain the report of the verification for a period of not less than 3 years.
(e)*Acceptable verification procedure.* An audit, including underlying paperwork, which was performed in the ordinary course of business according to generally accepted auditing standards by an independent and Qualified Auditor, shall serve as an acceptable verification procedure for all parties with respect to the information that is within the scope of the audit.
(f)*Consultation.* Before rendering a written report to a Copyright Owner or Performer, except where the auditor has a reasonable basis to suspect fraud and disclosure would, in the reasonable opinion of the auditor, prejudice the investigation of such suspected fraud, the auditor shall review the tentative written findings of the audit with the appropriate agent or employee of the Collective in order to remedy any factual errors and clarify any issues relating to the audit; Provided that the appropriate agent or employee of the Collective reasonably cooperates with the auditor to remedy promptly any factual errors or clarify any issues raised by the audit.
(g)*Costs of the verification procedure.* The Copyright Owner or Performer requesting the verification procedure shall pay the cost of the procedure, unless it is finally determined that there was an underpayment of 10% or more, in which case the Collective shall, in addition to paying the amount of any underpayment, bear the reasonable costs of the verification procedure. § 380.8 Unclaimed funds. If the Collective is unable to identify or locate a Copyright Owner or Performer who is entitled to receive a royalty distribution under this part, the Collective shall retain the required payment in a segregated trust account for a period of 3 years from the date of distribution. No claim to such distribution shall be valid after the expiration of the 3-year period. After expiration of this period, the Collective may apply the unclaimed funds to offset any costs deductible under 17 U.S.C. 114(g)(3). The foregoing shall apply notwithstanding the common law or statutes of any State. Dated: April 23, 2007. James Scott Sledge, Chief Copyright Royalty Judge. [FR Doc. E7-8128 Filed 4-30-07; 8:45 am] BILLING CODE 1410-10-P 72 83 Tuesday, May 1, 2007 Proposed Rules Part VII Department of Health and Human Services Centers for Medicare & Medicaid Services 42 CFR Part 418 Medicare Program; Hospice Wage Index for Fiscal Year 2008; Proposed Rule DEPARTMENT OF HEALTH AND HUMAN SERVICES Centers for Medicare & Medicaid Services 42 CFR Part 418 [CMS-1539-P] RIN 0938-AO72 Medicare Program; Hospice Wage Index for Fiscal Year 2008 AGENCY: Centers for Medicare & Medicaid Services (CMS), HHS. ACTION: Proposed rule. SUMMARY: This proposed rule would set forth the hospice wage index for fiscal year 2008. This proposed rule would also revise the methodology for updating the wage index for rural areas without hospital wage data and provide clarification of selected existing Medicare hospice regulations and policies. DATES: To be assured consideration, comments must be received at one of the addresses provided below, no later than 5 p.m. on July 2, 2007. ADDRESSES: In commenting, please refer to file code CMS-1539-P. Because of staff and resource limitations, we cannot accept comments by facsimile
(FAX)transmission. You may submit comments in one of four ways (no duplicates, please): 1. *Electronically.* You may submit electronic comments on specific issues in this regulation to *http://www.cms.hhs.gov/eRulemaking.* Click on the link “Submit electronic comments on CMS regulations with an open comment period.” (Attachments should be in Microsoft Word, WordPerfect, or Excel; however, we prefer Microsoft Word.) 2. *By regular mail.* You may mail written comments (one original and two copies) to the following address ONLY: Centers for Medicare & Medicaid Services, Department of Health and Human Services, *Attention:* CMS-1539-P, P.O. Box 8012, Baltimore, MD 21244-1850. Please allow sufficient time for mailed comments to be received before the close of the comment period. 3. *By express or overnight mail.* You may send written comments (one original and two copies) to the following address ONLY: Centers for Medicare & Medicaid Services, Department of Health and Human Services, *Attention:* CMS- *1539* -P, Mail Stop C4-26-05, 7500 Security Boulevard, Baltimore, MD 21244-1850. 4. *By hand or courier.* If you prefer, you may deliver (by hand or courier) your written comments (one original and two copies) before the close of the comment period to one of the following addresses. If you intend to deliver your comments to the Baltimore address, please call telephone number
(410)786-9994 in advance to schedule your arrival with one of our staff members. Room 445-G, Hubert H. Humphrey Building, 200 Independence Avenue, SW., Washington, DC 20201; or 7500 Security Boulevard, Baltimore, MD 21244-1850. (Because access to the interior of the HHH Building is not readily available to persons without Federal Government identification, commenters are encouraged to leave their comments in the CMS drop slots located in the main lobby of the building. A stamp-in clock is available for persons wishing to retain a proof of filing by stamping in and retaining an extra copy of the comments being filed.) Comments mailed to the addresses indicated as appropriate for hand or courier delivery may be delayed and received after the comment period. For information on viewing public comments, see the beginning of the SUPPLEMENTARY INFORMATION section. FOR FURTHER INFORMATION CONTACT: Terri Deutsch,
(410)786-9462. SUPPLEMENTARY INFORMATION: *Submitting Comments:* We welcome comments from the public on all issues set forth in this rule to assist us in fully considering issues and developing policies. You can assist us by referencing the file code CMS-1539-P and the specific “issue identifier” that precedes the section on which you choose to comment. *Inspection of Public Comments:* All comments received before the close of the comment period are available for viewing by the public, including any personally identifiable or confidential business information that is included in a comment. We post all comments received before the close of the comment period on the following Web site as soon as possible after they have been received: *http://www.cms.hhs.gov/eRulemaking.* Click on the link “Electronic Comments on CMS Regulations” on that Web site to view public comments. Comments received timely will also be available for public inspection as they are received, generally beginning approximately 3 weeks after publication of a document, at the headquarters of the Centers for Medicare & Medicaid Services, 7500 Security Boulevard, Baltimore, Maryland 21244, Monday through Friday of each week from 8:30 a.m. to 4 p.m. To schedule an appointment to view public comments, phone 1-800-743-3951. I. Background A. General 1. Hospice Care Hospice care is an approach to treatment that recognizes that the impending death of an individual warrants a change in the focus from curative care to palliative care for relief of pain and for symptom management. The goal of hospice care is to help terminally ill individuals continue life with minimal disruption to normal activities while remaining primarily in the home environment. A hospice uses an interdisciplinary approach to deliver medical, social, psychological, emotional, and spiritual services through use of a broad spectrum of professional and other caregivers, with the goal of making the individual as physically and emotionally comfortable as possible. Counseling services and inpatient respite services are available to the family of the hospice patient. Hospice programs consider both the patient and the family as a unit of care. Section 1861(dd) of the Social Security Act (the Act) provides for coverage of hospice care for terminally ill Medicare beneficiaries who elect to receive care from a participating hospice. Section 1814(i) of the Act provides payment for Medicare participating hospices. 2. Medicare Payment for Hospice Care Our regulations at 42 CFR part 418 establish eligibility requirements, payment standards and procedures, define covered services, and delineate the conditions a hospice must meet to be approved for participation in the Medicare program. Part 418 subpart G provides for payment in one of four prospectively-determined rate categories (routine home care, continuous home care, inpatient respite care, and general inpatient care) to hospices based on each day a qualified Medicare beneficiary is under a hospice election. B. Hospice Wage Index Our regulations at § 418.306(c) require each hospice's labor market to be established using the most current hospital wage data available, including any changes to the Metropolitan Statistical Areas
(MSAs)definitions, which have been superseded by Core Based Statistical Areas (CBSAs). Section 1814(i)(2)(D) of the Act requires Medicare to pay for hospice care furnished in an individual's home on the basis of the geographic location where the service is furnished. We have interpreted this to mean that the wage index value used is based upon the location of the beneficiary's home for routine home care and continuous home care and the location of the hospice agency for general inpatient and respite care. The hospice wage index is used to adjust payment rates for hospice agencies under the Medicare program to reflect local differences in area wage levels. The original hospice wage index was based on the 1981 Bureau of Labor Statistics hospital data and had not been updated since 1983. In 1994, because of disparity in wages from one geographical location to another, a committee was formulated to negotiate a wage index methodology that could be accepted by the industry and the government. This committee, functioning under a process established by the Negotiated Rulemaking Act of 1990, was comprised of national hospice associations; rural, urban, large and small hospices; multi-site hospices; consumer groups; and a government representative. On April 13, 1995, the Hospice Wage Index Negotiated Rulemaking Committee signed an agreement for the methodology to be used for updating the hospice wage index. In the August 8, 1997 **Federal Register** (62 FR 42860), we published a final rule implementing a new methodology for calculating the hospice wage index based on the recommendations of the negotiated rulemaking committee. The committee statement was included in the appendix of that final rule (62 FR 42883). The hospice wage index is updated annually. Our most recent annual update notice published in the September 1, 2006 **Federal Register** (71 FR 52080), set forth updates to the hospice wage index for FY 2007. On October 3, 2006, we published a correction notice in the **Federal Register** (71 FR 58415) and we published a subsequent correction notice on January 26, 2007 (72 FR 3856), to correct technical errors that appeared in the September 1, 2006 notice. 1. Changes to Core-Based Statistical Areas The annual update to the hospice wage index is published in the **Federal Register** and is based on the most current available hospital wage data, as well as any changes by the Office of Management and Budget
(OMB)to the definitions of MSAs. The August 4, 2005 final rule (70 FR 45130) set forth the adoption of the changes discussed in the OMB Bulletin No. 03-04 (June 6, 2003), which announced revised definitions for Micropolitan Statistical Areas and the creation of MSAs and Combined Statistical Areas. In adopting the OMB Core-Based Statistical Area
(CBSA)geographic designations, we provided for a 1-year transition with a blended wage index for all providers for FY 2006. For FY 2006, the hospice wage index for each provider consisted of a blend of 50 percent of the FY 2006 MSA-based wage index and 50 percent of the FY 2006 CBSA-based wage index. As discussed in the August 4, 2005 final rule and in the September 1, 2006 notice, we will use the full CBSA-based wage index values as presented in Tables A and B of this proposed rule for FY 2008. 2. Raw Wage Index Values Raw wage index values (that is, inpatient hospital pre-floor and pre-reclassified wage index values) as described in the August 8, 1997 hospice wage index final rule (62 FR 42860), are subject to either a budget neutrality adjustment or application of the wage index floor. Raw wage index values of 0.8 or greater are adjusted by the budget neutrality adjustment factor. Budget neutrality means that, in a given year, estimated aggregate payments for Medicare hospice services using the updated wage index values will equal estimated payments that would have been made for these services if the 1983 wage index values had remained in effect. To achieve this budget neutrality, the raw wage index is multiplied by a budget neutrality adjustment factor. The budget neutrality adjustment factor is calculated by comparing what we would have paid using current rates and the 1983 wage index to what would be paid using current rates and the new wage index. The budget neutrality adjustment factor is computed and applied annually. For the FY 2008 hospice wage index in the proposed rule, FY 2007 hospice payment rates were used in the budget neutrality adjustment factor calculation. Raw wage index values below 0.8 are adjusted by the greater of:
(1)The hospice budget neutrality adjustment factor; or
(2)the hospice wage index floor (a 15 percent increase) subject to a maximum wage index value of 0.8. For example, if County A has a pre-floor, pre-reclassified hospital wage index (raw wage index value) of 0.4000, we would perform the following calculations using the budget neutrality factor (which for this example is 1.060988) and the hospice wage index floor to determine County A's hospice wage index: Raw wage index value below 0.8 multiplied by the budget neutrality adjustment factor: (0.4000 × 1.060988 = 0.4244). Raw wage index value below 0.8 multiplied by the hospice wage index floor: (0.4000 × 1.15 = 0.4600). Based on these calculations, County A's hospice wage index would be 0.4600. 3. Hospice Payment Rates Section 4441(a) of the Balanced Budget Act of 1997
(BBA)amended section 1814(i)(1)(C)(ii) of the Act to establish updates to hospice rates for FYs 1998 through 2002. Hospice rates were to be updated by a factor equal to the market basket index, minus 1 percentage point. However, neither the BBA nor subsequent legislation specified the market basket adjustment to be used to compute payment for FY 2008. Therefore, payment rates for FY 2008 will be updated according to section 1814(i)(1)(C)(ii)(VII) of the Act, which states that the update to the payment rates for subsequent FYs will be the market basket percentage for the fiscal year. Accordingly, the FY 2008 update to the payment rates will be the full market basket percentage increase for FY 2008. This rate update is implemented through a separate administrative instruction and is not part of this notice. Historically, the rate update has been published through a separate administrative instruction issued annually in July to provide adequate time to implement system change requirements. Providers determine their payment rates by applying the wage index in this notice to the labor portion of the published hospice rates. 4. Proxy for the Hospital Market Basket As discussed above, the hospice payment rates are adjusted each year based upon the full hospital market basket. In the FY 2007 update notice (72 FR 52082) issued on September 1, 2006, we indicated that beginning in April 2006, with the publication of March 2006 data, the Bureau of Labor Statistic's (BLS's) Employment Cost Index
(ECI)began using a different classification system, the North American Industrial Classification System (NAICS), instead of the Standard Industrial Classification System (SIC), which no longer exists. The ECIs had been used as the data source for wages and salaries and other price proxies in the hospital market basket. In the FY 2007 update notice we noted that no changes would be made to the usage of the NAICS-based ECI, however, input was solicited on this issue. We received no comments and as a result, we are not proposing any changes. II. Provisions of the Proposed Rule A. Annual Update to the Hospice Wage Index The hospice wage index presented in this proposed rule would be effective October 1, 2007 through September 30, 2008. We note that we are not proposing any modifications to the hospice wage index methodology. In accordance with our regulations and the agreement signed with other members of the Hospice Wage Index Negotiated Rulemaking Committee, we are using the most current hospital data available to us. For this proposed rule, the FY 2007 hospital wage index was the most current hospital wage data available for calculating the FY 2008 hospice wage index values. We used the FY 2007 pre-reclassified and pre-floor hospital area wage index data for this calculation. Payment rates for each of the four levels of care are adjusted annually based upon the hospital market basket for that year and are promulgated administratively to allow for sufficient time for system changes and provider notification. Due to the need to ensure appropriate time for implementing changes, the latest adjustments to these payment rates were not incorporated into this proposed rule. As noted above, for FY 2008, the hospice wage index values will be based solely on the adoption of the CBSA-based labor market definitions and its wage index. We continue to use the most recent pre-floor and pre-reclassified hospital wage index data available (FY 2003 hospital wage data). A detailed description of the methodology used to compute the hospice wage index is contained in both the September 4, 1996 proposed rule (61 FR 46579) and the August 8, 1997 final rule (62 FR 42860). All wage index values are adjusted by a budget-neutrality factor of 1.066028 and are subject to the wage index floor adjustment, if applicable. We completed all of the calculations described in section 2.B below and included them in the wage index values reflected in Tables A and B of the Addendum. Specifically, Table A reflects the FY 2008 wage index values for urban areas under the CBSA designations. Table B reflects the FY 2008 wage index values for rural areas under the CBSA designations. B. Rural Areas Without Hospital Wage Data (If you choose to comment on issues in this section, please include the caption “Rural Areas without Wage Data” at the beginning of your comments.) When adopting OMB's new labor market designations, we identified some geographic areas where there were no hospitals, and thus, no hospital wage index data on which to base the calculation of the hospice wage index (70 FR 45135, August 4, 2005). For FY 2006 and FY 2007, we adopted a policy to use the FY 2005 pre-floor, pre-reclassified hospital wage index value for rural areas when no rural hospital wage data were available. We also adopted the policy that for urban labor markets without an urban hospital from which a hospital wage index data could be derived, all of the CBSAs within the State would be used to calculate a statewide urban average wage index data to use as a reasonable proxy for these areas. We did not receive any public comments regarding our policy to calculate an urban wage index, using an average of all of the urban CBSA wage index data within the State, for urban labor markets without an urban hospital from which a hospital wage index could be derived. Consequently, in the August 2005 final rule and in the August 2006 update notice, we applied the average wage index data from all urban areas lacking hospital wage data in that state. Currently, the only CBSA that is affected by this is CBSA 25980 Hinesville-Fort Stewart, Georgia. We propose to continue this approach for urban areas where there are no hospitals and, thus, no hospital wage index data on which to base the calculations for the FY 2008 and subsequent hospice wage indexes. Therefore, the pre-floor, pre-reclassified wage index data for urban CBSA 25980, Hinesville-Fort Stewart, GA is calculated as the average wage index data of all urban areas in Georgia with a value of 0.9178. Under the CBSA labor market areas, there are no rural hospitals in rural locations in Massachusetts and Puerto Rico. Since there was no rural proxy for more recent rural data within those areas, in the August 2005 proposed rule (70 FR 45135), we proposed applying the FY 2005 pre-floor, pre-reclassified hospital wage index value to rural areas where no hospital wage data are available. We did not receive any public comments on this matter, either. Consequently, in the August 2005 final rule and in the August 2006 update notice, we applied the FY 2005 pre-floor, pre-reclassified hospital wage index data for rural areas lacking hospital wage data in that state in both FY 2006 and FY 2007 for rural Massachusetts and rural Puerto Rico. Since we have used the same wage index value from FY 2005 for these areas for the previous two fiscal years, we believe it is appropriate to consider alternatives in our methodology to update the wage index for rural areas without hospital wage index data. We believe that the best imputed proxy for rural areas, would:
(1)Use pre-floor, pre-reclassified hospital data;
(2)use the most local data available to impute a rural wage index;
(3)be easy to evaluate; and,
(4)be easy to update from year-to-year. Although our current methodology uses local, rural pre-floor, pre-reclassified hospital wage data, this method cannot be updated from year-to-year. Therefore, in cases where there is a rural area without rural hospital wage data, we propose using the average pre-floor, pre-reclassified wage index data from all contiguous CBSAs to represent a reasonable proxy for the rural area. While this approach does not use rural data, it does use pre-floor, pre-reclassified hospital wage data, it is easy to evaluate, it is easy to update from year-to-year, and it uses the most local data available. In determining an imputed rural wage index, we interpret the term contiguous to mean as sharing a border. For example, in the case of Massachusetts, the entire rural area consists of Dukes and Nantucket counties. We have determined that the borders of Dukes and Nantucket counties are contiguous with Barnstable and Bristol counties. Under the proposed methodology, the pre-floor, pre-reclassified wage index values for the counties of Barnstable (CBSA 12700, Barnstable Town, MA) of 1.2539 and Bristol (CBSA 39300, Providence-New Bedford-Fall River, RI-MA) of 1.0783 would be averaged resulting in an imputed pre-floor, pre-reclassified rural wage index of 1.1661 for rural Massachusetts for FY 2008. The impact of utilizing the proposed methodology is captured in the impact analysis (Table 1). As shown in Table B, the proposed wage index value for FY 2008 for rural Massachusetts is 1.2431. If we had retained the current methodology, the rural Massachusetts wage index would have been 1.0891. While we believe that this policy could be readily applied to other rural areas that lack hospital wage data (possibly due to hospitals converting to a different provider type, such as a CAH, that do not submit the appropriate wage data), should a similar situation arise in the future, we may re-examine this policy. However, we do not believe that this policy would be appropriate for Puerto Rico. There are sufficient economic differences between hospitals in the United States and those in Puerto Rico, including the payment of hospitals in Puerto Rico using blended Federal/Commonwealth-specific rates that we believe that a separate and distinct policy for Puerto Rico is necessary. Consequently, any alternative methodology for imputing a wage index for rural Puerto Rico would need to take into account those differences. Our policy of imputing a rural wage index based on the wage index(es) of CBSAs contiguous to the rural area in question does not recognize the unique circumstances of Puerto Rico. While we have not yet identified an alternative methodology for imputing a wage index for rural Puerto Rico, we will continue to evaluate the feasibility of using existing hospital wage data and, possibly, wage data from other sources. Accordingly, we propose to continue using the most recent pre-floor, pre-reclassified wage index previously available for Puerto Rico, which is 0.4047. C. Nomenclature Changes (If you choose to comment on issues in this section, please include the caption “Nomenclature Changes” at the beginning of your comments.) In the August 4, 2005 final rule and in the September 1, 2006 update notice, we noted that the Office of Management and Budget
(OMB)published a bulletin that changed the titles to certain CBSAs. Since the publication of the Hospice FY 2006 update notice, OMB published additional bulletins that updated the CBSAs. Specifically, OMB added or deleted certain CBSA numbers and revised certain titles. Accordingly, in this proposed rule, we are proposing to clarify that this and all subsequent Hospice rules and notices are considered to incorporate the CBSA changes published in the most recent OMB bulletin, that applies to the hospital wage data used to determine the current hospice wage index. The proposed tables reflect changes made by these bulletins. The OMB bulletins may be accessed at *http://www.whitehouse.gov/omb/bulletins/index.html.* D. Payment for Hospice Care Based on Location Where Care Is Furnished (If you choose to comment on issues in this section, please include the caption “Site of Service” at the beginning of your comments) Hospice providers receive payment for four levels of care based upon the individual's needs. Section 4442 of the BBA amended section 1814(i)(2) of the Act, effective for services furnished on or after October 1, 1997, required the application of the local wage index value of the geographic location at which the service is furnished for hospice care provided in the home. This provision has been codified in our regulations at 418.302(g). Prior to this provision, local wage index values were applied based on the geographic location of the hospice provider, regardless of where the hospice care was furnished. We believe that for the majority of hospice providers the office and the site for the provision of home and inpatient care occur in the same geographic area. However, with the substantial growth of hospice providers in multiple states and with multiple sites within a State, hospice providers have been able to inappropriately maximize reimbursement by locating their offices in high-wage areas and delivering services in a lower-wage area. We also believe that hospice providers are also able to inappropriately maximize reimbursement by locating their inpatient services either directly or under contractual arrangements in lower wage areas than their offices. Section 4442 of the BBA applies the wage index value of a home's geographic location for services provided there, but is silent as to what wage index value should be used for hospice services provided in an inpatient setting. We believe that the application of the wage index values, for rate adjustments on the geographic area, where the hospice care is furnished provides a reimbursement rate that is a more accurate reflection of the wages paid by the hospice for the staff used to furnish care. We also believe that payment should reflect the location of the services provided and not the location of an office. As a result, we are proposing that effective January 1, 2008, all payment rates (routine home care, continuous home care, inpatient respite and general inpatient care) be adjusted by the geographic wage index value of the area where hospice services are provided. In other words, the wage component of each payment rate is multiplied by the wage index value applicable to the location in which the hospice services are provided. We are proposing to amend 418.302(g) to reflect this proposed change. Currently, hospice claims do not contain information identifying the location of the facility where general inpatient and respite care are provided. Therefore, we are unable to predict the savings or costs associated with the changes associated with this proposed provision. However, we believe that the impact of implementing this proposal will be negligible. E. Clarification of Selected Existing Medicare Hospice Regulations and Policies 1. Educational Requirements for Nurse Practitioners (If you choose to comment on issues in this section, please include the caption “Nurse Practitioners” at the beginning of your comments.) On December 8, 2003, the Congress enacted the Medicare Prescription Drug, Improvement, and Modernization Act
(MMA)of 2003 (Pub. L. 108-173). Section 408 of the MMA, Recognition of Attending Nurse Practitioners as Attending Physicians to Serve Hospice Patients, amended sections 1861(dd)(3)(B) and 1814(a)(7) of the Act to add nurse practitioners
(NPs)to the definition of an attending physician for beneficiaries who have elected the hospice benefit. Section 408 of the MMA was implemented through an administrative issuance (Change Request
(CR)3226, Transmittals 22 and 304, September 24, 2004). In the FY 2006 Final Rule (70 FR 45130, August 4, 2005), we revised § 418.3 to implement the provisions of section 408 of the MMA. Section 418.3 indicated (under clause (1)(ii) of the definition of “attending physician”) that the nurse practitioner “* * * meet the training, education, and experience requirements as the Secretary may prescribe * * *”. We believe that the definition for nurse practitioners under the Medicare hospice benefit should reflect the definition as established for the Medicare benefit found at § 410.75. To ensure consistency, we propose to revise the definition of “attending physician” at § 418.3 to cross reference the requirement in § 410.75(b). 2. Care Giver Breakdown and General Inpatient Care (If you choose to comment on issues in this section, please include the caption “Care Giver and General Inpatient Care” at the beginning of your comments.) The Medicare hospice benefit places emphasis on the provision of items and services to enable an individual to remain at home in the company of family and friends. Section 1861(dd)(1)(G) of the Act provides for short term inpatient hospice care to be available when an individual's pain and symptoms must be closely monitored or the intensity of interventions that are required cannot be provided in any other settings. In recognition of the stress in providing care for an individual with a terminal diagnosis, inpatient respite care is available for family members, who serve as the primary caregivers, to obtain rest for a period of no more than five days at a time. Medicare policy as described in chapter 9 of the Medicare Benefit Policy Manual, states that skilled nursing care may be required by a patient whose home support has broken down, if this breakdown makes it no longer feasible to furnish needed care in the home setting. If the hospice and the caregiver, working together, are no longer able to provide the necessary skilled nursing care in the individual's home, and if the individual's pain and symptom management can no longer be provided at home, then the individual may be eligible for a short term general inpatient level of care. However, it has come to our attention that some hospice providers are requesting payment for the “general inpatient” level of care for circumstances that do not qualify under the statute, our regulations at § 418.202(e) or Medicare hospice policy. In other words, some hospices are billing Medicare for “caregiver breakdown” at the higher “general inpatient” level, rather than the lower payment for “inpatient respite” or “routine home care” levels of care. To receive payment for “general inpatient care” under the Medicare hospice benefit, beneficiaries *must* require an intensity of care directed towards pain control and symptom management that cannot be managed in any other setting. While there is nothing prohibiting a Medicare approved facility from serving as the individual's home, it is the level of care provided to meet the individual's needs which determine payment rates for Medicare services. “Caregiver breakdown” should not be billed as “general inpatient care” regardless of where services are provided, unless the intensity-of-care requirement is met. If the individual is no longer able to remain in his or her home, but the required care does not meet the requirements for “general inpatient care”, hospices should bill this care as “inpatient respite care”, payable for no more than 5 days, until alternative arrangements can be made. As explained, this is a clarification of current Medicare policy and is not anticipated to create new limitations on access to hospice care. However, we are clarifying that the level of care provided, not the location of care, is what determines the appropriate level of payment. Additionally, the circumstances addressed with this policy, and the clarification discussed above, should not be construed as similar to situations where an individual does not have family or friends or other means that are able to take on the role of a caregiver when a hospice election is made. The Medicare hospice benefit provides for care that is medically reasonable and necessary for the palliation and management of the terminal and related conditions, and is structured in such a way to enable the individual with a terminal condition to remain at home, as long as possible, in the company of family and friends. We recognize the difficulties surrounding the provision of hospice care to an individual who is terminally ill and who does not have caregivers at home. This may be a challenge in rural areas. Section 409 of the MMA established the Rural Hospice Demonstration which hopes to test alternative mechanisms for providing hospice services for beneficiaries who lack an appropriate caregiver and who reside in rural areas. However, we intend to monitor the usage of the general inpatient care. We are providing this as clarification and therefore are not proposing any changes in existing statute, regulation or policy manual. 3. Certification of Terminal Illness (If you choose to comment on issues in this section, please include the caption “Certification” at the beginning of your comments.) Section 1814(a)(7)(A)(i) of the Act stipulates that the individual's attending physician and the hospice medical director initially certify the individual's terminal diagnosis with prognosis of six months or less if the disease runs its normal course. The requirements of the physician certification, including supportive documentation were discussed in the hospice care amendment proposed rule (67 CFR 70363) and final rule (70 CFR 70548). In these rules, we indicated that a direct consultation between the hospice medical director and the attending physician was not a requirement and that information supporting the terminal diagnosis could be obtained through the hospice admission nurse. We are aware that the intent of this has been construed by some providers, to permit the admission nurse, utilizing documents such as local coverage decisions, to determine eligibility for hospice services and certify the individual's terminal diagnosis. This interpretation is incorrect. We have permitted the hospice nurses to obtain information to be used by the hospice medical director as part of the medical documents used in his or her determination of the terminal diagnosis and eligibility for the Medicare hospice benefit. The statute is explicit in the requirement that the physician and medical director determine the prognosis and his or her signature on the certification attests to that fact. We will provide further clarification in administrative instructions. III. Collection of Information Requirements This document does not impose any information collection and recordkeeping requirements. Consequently, it need not be reviewed by the Office of Management and Budget under the authority of the Paperwork Reduction Act of 1995 (44 U.S.C. 35). IV. Response to Comments Because of the large number of public comments we normally receive on **Federal Register** documents, we are not able to acknowledge or respond to them individually. We will consider all comments we receive by the date and time specified in the DATES section of this preamble, and, when we proceed with a subsequent document, we will respond to the comments in the preamble to that document. V. Regulatory Impact Analysis A. Overall Impact We have examined the impacts of this proposed rule as required by Executive Order 12866 (September 1993, Regulatory Planning and Review), the Regulatory Flexibility Act
(RFA)(September 19, 1980, Pub. L. 96-354), section 1102(b) of the Act, the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4), and Executive Order 13132. We estimated the impact on hospices, as a result of the proposed changes to the FY 2008 hospice wage index. As discussed previously, the methodology for computing the wage index was determined through a negotiated rulemaking committee and implemented in the August 8, 1997 final rule (62 FR 42860). This proposed rule updates the hospice wage index in accordance with our regulation and that methodology, incorporating the adoption of the CBSA designations used in the FY 2007 hospital wage index data. • Table 1 categorizes the impact on hospices by various geographic and provider characteristics. We estimate that the total hospice payments will decrease $538,000 as a result of the proposed FY 2008 wage index values. We anticipate that the final rule will more accurately project payment for FY 2008, based upon changes in the wage index values. • Table A reflects the FY 2008 wage index values for urban areas designations. • Table B reflects the FY 2008 wage index values for rural areas designations. Executive Order 12866 (as amended by Executive Order 13258, which merely reassigns responsibility of duties) directs agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). A regulatory impact analysis
(RIA)must be prepared for major rules with economically significant effects ($100 million or more in any 1 year). We have determined that this notice is not an economically significant rule under this Executive Order. The RFA requires agencies to analyze options for regulatory relief of small businesses. For purposes of the RFA, small entities include small businesses, nonprofit organizations, and small governmental jurisdictions. Most hospices and most other providers and suppliers are small entities, either by nonprofit status or by having revenues of $6.5 million to $31.5 million in any 1 year (for details, see the Small Business Administration's regulation at 65 FR 69432, that sets forth size standards for health care industries). For purposes of the RFA, most hospices are small entities. As indicated in Table 1 below, there are 2,819 hospices. Approximately 81 percent of Medicare certified hospices are identified as voluntary, government, or other agencies and, therefore, are considered small entities. Because the National Hospice and Palliative Care Organization estimates that approximately 79 percent of hospice patients are Medicare beneficiaries, we have not considered other sources of revenue in this analysis. Furthermore, the wage index methodology was previously determined by consensus, through a negotiated rulemaking committee that included representatives of national hospice associations; rural, urban, large and small hospices; multi-site hospices; and consumer groups. Based on all of the options considered, the committee agreed on the methodology described in the committee statement, and it was adopted into regulation in the August 8, 1997 final rule. In developing the process for updating the wage index in the 1997 final rule, we considered the impact of this methodology on small entities and attempted to mitigate any potential negative effects. In addition, section 1102(b) of the Act requires us to prepare a regulatory impact analysis if a rule may have a significant impact on the operations of a substantial number of small rural hospitals. This analysis must conform to the provisions of section 603 of the RFA. For purposes of section 1102(b) of the Act, we define a small rural hospital as a hospital that is located outside a CBSA and has fewer than 100 beds. We have determined that this notice would not have a significant impact on the operations of a substantial number of small rural hospitals. We are not preparing an analysis for the RFA because we have determined that this rule will not have a significant economic impact on a substantial number of small entities. Section 202 of the Unfunded Mandates Reform Act of 1995 also requires that agencies assess anticipated costs and benefits before issuing any rule that may result in expenditure in any 1 year by State, local, and tribal governments, in the aggregate, or by the private sector, of $120 million or more. This notice is not anticipated to have an effect on State, local, or tribal governments or on the private sector of $120 million or more. Executive Order 13132 establishes certain requirements that an agency must meet when it promulgates a proposed rule (and subsequent final rule) that imposes substantial direct requirement costs on State and local governments, preempts State law, or otherwise has Federalism implications. We have reviewed this notice under the threshold criteria of Executive Order 13132, Federalism, and have determined that it would not have an impact on the rights, roles, and responsibilities of State, local, or tribal governments. In accordance with the provisions of Executive Order 12866, this regulation was reviewed by the Office of Management and Budget. B. Anticipated Effects We are unable to quantify the extent of the usage of the general inpatient level of care in the event of caregiver breakdown and are, therefore, unable to definitively anticipate the impact of our clarification of the general inpatient level of care policy in the event of caregiver breakdown. For this reason, we solicit comment on what the impact of our clarification might be. Based on anecdotal evidence as well as substantial increases in the number of claims submitted for general inpatient care, however, we believe a small proportion of patient days attributed to general inpatient care would be appropriately allocated to inpatient respite care with this clarification. Significant savings could be realized even if only a small proportion of patient days attributed to general inpatient care were allocated to inpatient respite care. For example, to determine the impact of allocating 5.0 percent of general inpatient care days to inpatient respite care, we used the FY 2005 patient days, expenditures and number of beneficiaries electing the hospice benefit to estimate the impact of the clarification of existing policy in this proposed rule. The number of inpatient days was adjusted from 1,250,678 to 1,188,144. The number of inpatient respite days was adjusted from 96,646 to 159,180. While inpatient respite expenditures increased from $14,000,000 to $23,058,570, general inpatient care expenditures decreased from $737,300,000 to $700,435,000. In total, if 5.0 percent of patient days that were attributed to general inpatient care in FY 2005 were allocated to the inpatient respite level of care, it would have resulted in net savings of $27,806,430. The impact analysis of this notice represents the projected effects of the changes in the hospice wage index from FY 2007 to FY 2008. We estimate the effects by estimating payments for FY 2008 utilizing the FY 2007 wage index values and the full implementation of the CBSA designations while holding all other payment variables constant. We note that certain events may combine to limit the scope or accuracy of our impact analysis, because such an analysis is future oriented and, thus, susceptible to forecasting errors due to other changes in the forecasted impact time period. The nature of the Medicare program is such that the changes may interact, and the complexity of the interaction of these changes could make it difficult to predict accurately the full scope of the impact upon hospices. For the purposes of this proposed rule, we compared estimated payments using the FY 1983 hospice wage index to estimated payments using the FY 2008 wage index and determined the hospice wage index to be budget neutral. Budget neutrality means that, in a given year, estimated aggregate payments for Medicare hospice services using the FY 2008 wage index would equal estimated aggregate payments that would have been made for the same services if the 1983 wage index had remained in effect. Budget neutrality to 1983 does not imply that estimated payments would not increase since the budget neutrality applies only to the wage index portion and not the total payment rate, which accommodates inflation. As discussed above, we use the latest claims file available to us to develop the impact table when we issue the annual yearly wage index update. For the purposes of this proposed rule, data were obtained from the National Claims History file using FY 2005 claims processed through June 2006, which were the most recent available data. We deleted bills from hospice providers that have since closed. For the purposes of this proposed rule, this file is adequate to demonstrate the impact of the FY 2008 wage index values and is not intended to project the anticipated expenditures for FY 2008. We anticipate that the final rule will more accurately project payment for FY 2008. This impact analysis compares hospice payments using the FY 2007 hospice wage index to the estimated payments using the FY 2008 wage index. We note that estimated payments for FY 2008 are determined by using the wage index for FY 2008 and payment rates for FY 2007. As noted in previous sections, payment rates for FY 2008 are published through administrative issuance. Table 1 demonstrates the results of our analysis. In column 1 we indicate the number of hospices included in our analysis. In column 2, we indicate the number of routine home care days that were included in our analysis, although the analysis was performed on all types of hospice care. Column 3 estimates payments using the FY 2007 wage index values and the FY 2007 payment rates. Column 4 estimates payments using FY 2008 wage index values as well as the FY 2007 payment rates. Column 5 compares columns 3 and 4 and shows the percentage change in estimated hospice payments made based on the hospice category. Table 1 also categorizes hospices by various geographic and provider characteristics. The first row displays the aggregate result of the impact for all Medicare-certified hospices. The second and third rows of the table categorize hospices according to their geographic location (urban and rural). Our analysis indicated that there are 1,858 hospices located in urban areas and 961 hospices located in rural areas. The next two groupings in the table indicate the number of hospices by census region, also broken down by urban and rural hospices. The sixth grouping shows the impact on hospices based on the size of the hospice's program. We determined that the majority of hospice payments are made at the routine home care rate. Therefore, we based the size of each individual hospice's program on the number of routine home care days provided in FY 2006. The next grouping shows the impact on hospices by type of ownership. The final grouping shows the impact on hospices defined by whether they are provider-based or freestanding. As indicated in Table 1 below, there are 2,819 hospices. Approximately 81 percent of Medicare-certified hospices are identified as voluntary, government, or other agencies and, therefore, are considered small entities. Because the National Hospice and Palliative Care Organization estimates that approximately 79 percent of hospice patients are Medicare beneficiaries, we have not considered other sources of revenue in this analysis. Furthermore, the wage index methodology was previously determined by consensus, through a negotiated rulemaking committee that included representatives of national hospice associations; rural, urban, large, and small hospices; multi-site hospices; and consumer groups. Based on all of the options considered, the committee agreed on the methodology described in the committee statement, and it was adopted into regulation in the August 8, 1997 final rule. In developing the process for updating the wage index in the 1997 final rule, we considered the impact of this methodology on small entities and attempted to mitigate any potential negative effects. As stated previously, the following discussions are limited to demonstrating trends rather than projected dollars. We used the CBSA designations and wage indices as well as the data from FY 2005 claims processed through June 2006 in developing the impact analysis. For FY 2008 the wage index is the variable that differs between the FY 2007 payments and the FY 2008 estimated payments. FY 2007 payment rates are used for both FY 2007 actual payments and the FY 2008 estimated payments. The FY 2008 payment rates will be adjusted to reflect the full FY 2007 hospital market basket, as required by section 1814(i)(1)(C)(ii)(VII) of the Act. As previously noted, we publish these rates through administrative issuances. As discussed in the FY 2006 final rule (70 FR 45129), hospice agencies may utilize multiple wage indices to compute their payments based on potentially different geographic locations of the beneficiary for routine and continuous home care or the CBSA for the location of the hospice agency for respite and general inpatient care. For this analysis, we use payments to the hospice in the aggregate based on the location of the hospice. The impact of hospice wage index changes have been analyzed according to the type of hospice, geographic location, type of ownership, hospice base, and size. Our analysis shows that most hospices are in urban areas and provide the vast majority of routine home care days. Most hospices are medium sized followed by large hospices. Hospices are almost equal in numbers by ownership with 1,231 designated as non-profit and 1,265 as proprietary. The vast majority of hospices are freestanding. 1. Hospice Size Under the Medicare hospice benefit, hospices can provide four different levels of care days. The majority of the days provided by a hospice are routine home care days
(RHC)representing over 70 percent of the services provided by a hospice. Therefore, the number of routine home care days can be used as a proxy for the size of the hospice, that is, the more days of care provided, the larger the hospice. As discussed in the August 4, 2005 final rule, we currently use three size designations to present the impact analyses. The three categories are: Small agencies having 0 to 3,499 RHC days; medium agencies having 3,500 to 19,999 RHC days; and large agencies having 20,000 or more RHC days. Using RHC days as a proxy for size, our analysis indicates that the proposed FY 2008 wage index values are anticipated to have virtually no impact on hospice providers, with a slight decrease of 0.1 percent anticipated for small hospices while no change is anticipated for medium or large hospices. 2. Geographic Location Our analysis demonstrates that the proposed FY 2008 wage index values will result in little change in estimated payments with urban hospices anticipated to experience no change while rural hospices are anticipated to experience a slight increase of 0.2 percent. The greatest increase of 0.9 percent is anticipated to be experienced by the Mountain regions, followed by an increase for East North Central of 0.6 percent and Pacific regions of 0.5 percent. The remaining urban regions are anticipated to experience a decrease ranging from 0.6 percent in the East South Central region to 0.1 percent in the Middle Atlantic region. The greatest decrease of 2.6 percent is anticipated for Puerto Rico. For rural hospices, the South Atlantic region and Puerto Rico are anticipated to experience no change. Two regions are anticipated to experience a decrease of 0.9 percent for New England and 0.4 percent for the mountain regions. The remaining regions are anticipated to experience an increase ranging from 0.2 percent for the East North Central region to 0.6 percent for the Middle Atlantic and East South Central regions. 3. Type of Ownership By type of ownership, non-profit hospices are anticipated to experience no change in payment while government hospices are anticipated to experience a slight increase of 0.1 percent. Slight decreases are anticipated for proprietary hospices of 0.1 percent and 0.2 percent for other categories. 4. Hospice Base For hospice-based facilities, a decrease of 0.1 percent in payment is anticipated for freestanding facilities. Home health, hospital and skilled nursing facilities area anticipated to experience an increase of 0.1, 0.2 and 0.7 percent respectively. BILLING CODE 4120-01-P EP01MY07.000 EP01MY07.001 C. Conclusion Our impact analysis compared hospice payments by using the FY 2007 wage index to the estimated payments using the FY 2008 wage index. Through the analysis, we estimate that total hospice payments will effectively be budget neutral with a negligible decrease from FY 2007 by $538,000. Additionally, we compared estimated payments using the FY 1983 hospice wage index to estimated payments using the FY 2008 wage index and determined the current hospice wage index to be budget neutral, as required by the negotiated rulemaking committee. As noted above, the payment rates used reflect the FY 2007 rates. The FY 2008 payment rates will be adjusted to reflect the full FY 2008 hospital market basket, as required by section 1814(i)(1)(C)(ii)(VII) of the Act. We publish these rates through administrative issuances. In accordance with the provisions of Executive Order 12866, this regulation was reviewed by the Office of Management and Budget. List of Subjects for 42 CFR Part 418 Health facilities, Hospice care, Medicare, Reporting and recordkeeping requirements. For the reasons set forth in the preamble, the Centers for Medicare & Medicaid Services would amend 42 CFR part 418 as set forth below: PART 418—HOSPICE CARE 1. The authority citation for part 418 continues to read as follows: Authority: Secs. 1102 and 1871 of the Social Security Act (42 U.S.C. 1302 and 1395hh). Subpart A—General Provision and Definitions 2. Section 418.3 is amended by revising paragraph (1)(ii) in the definition of “attending physician” to read as follows: § 418.3 Definitions. *Attending Physician* means a—(1)(i) * * *
(ii)Nurse practitioner who meets the training, education, and experience requirements as described in § 410.75 (b). Subpart G—Payment for Hospice Care 3. Section 418.302 is amended by revising paragraph
(g)to read as follows: § 418.302 Payment procedures for hospice care.
(g)Payment for routine home care, continuous home care, general inpatient care and inpatient respite care is made on the basis of the geographic location where the services are provided. (Catalog of Federal Domestic Assistance Program No. 93.773, Medicare—Hospital Insurance; and Program No. 93.774, Medicare—Supplementary Medical Insurance Program) Dated: March 15, 2007. Leslie V. Norwalk, Acting Administrator, Centers for Medicare & Medicaid Services. Approved: April 11, 2007. Michael O. Leavitt, Secretary. BILLING CODE: 4120-01-P EP01MY07.002 EP01MY07.003 EP01MY07.004 EP01MY07.005 EP01MY07.006 EP01MY07.007 EP01MY07.008 EP01MY07.009 EP01MY07.010 EP01MY07.011 EP01MY07.012 EP01MY07.013 EP01MY07.014 EP01MY07.015 EP01MY07.016 EP01MY07.017 EP01MY07.018 EP01MY07.019 EP01MY07.020 EP01MY07.021 EP01MY07.022 EP01MY07.023 EP01MY07.024 EP01MY07.025 EP01MY07.026 EP01MY07.027 EP01MY07.028 EP01MY07.029 EP01MY07.030 EP01MY07.031 EP01MY07.032 EP01MY07.033 EP01MY07.034 EP01MY07.035 EP01MY07.036 EP01MY07.037 EP01MY07.038 EP01MY07.039 EP01MY07.040 EP01MY07.041 EP01MY07.042 EP01MY07.043 EP01MY07.044 EP01MY07.045 EP01MY07.046 [FR Doc. 07-2120 Filed 4-26-07; 4:00 pm]
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CFR
- What size standards has SBA identified by North American Industry Classification System codes?§ 121.201
- Permit requirements.§ 51.165
- Statutory restriction on new sources.§ 52.24
- Applicability and designation of affected facility.§ 60.480
- Standards: General.§ 60.482-1
- Legally enforceable procedures.§ 51.160
- Definitions.§ 51.100
- Categorical exclusions not subject to the Federal laws and authorities cited in § 50.4.§ 50.19
- When granted.§ 353.1
- Delivering statements of account.§ 380.3
- Designated collection and distribution organizations for reports of use of sound recordings under statutory license.§ 370.5
- Reports of use of sound recordings under statutory license for preexisting subscription services.§ 370.3
- Satellite carrier statements of account covering statutory licenses for secondary transmissions.§ 201.11
- Statements of Account covering compulsory licenses for secondary transmissions by cable systems.§ 201.17
- Statements of Account for digital audio recording devices or media.§ 201.28
U.S. Code
- Purposes§ 3501
- Regulation of fuels§ 7545
- Establishment, functions, and activities§ 272
- SHORT TITLE.§ 801
- EXPEDITED PROCESSING OF REQUESTS FOR JAPANESE IMPERIAL GOVERNMENT RECORDS.§ 804
- Recordkeeping, inspections, monitoring, and entry§ 7414
- Definitions§ 7550
- Public information; agency rules, opinions, orders, records, and proceedings§ 552
- General exceptions to the jurisdictional immunity of a foreign state§ 1605
- Statements or entries generally§ 1001
- Federal enforcement§ 7413
- Definitions§ 7479
- Definitions and declaration of policy§ 101
- Congressional findings and declaration of purpose§ 7401
- Low-income housing assistance§ 1437f
- Definitions§ 601
- Congressional declaration of purpose§ 4321
- Proceedings of Copyright Royalty Judges§ 803
- Institution of proceedings§ 804
- Subject matter of copyright: In general§ 102
- Exclusive rights in copyrighted works§ 106
- Scope of exclusive rights in sound recordings§ 114
- Limitations on exclusive rights: Ephemeral recordings§ 112
- Exemption from tax on corporations, certain trusts, etc.§ 501
- Copyright Royalty Judgeships; staff§ 802
- Rules and regulations; impact analyses of Medicare and Medicaid rules and regulations on small rural hospitals§ 1302
48 references not yet in our index
- 40 CFR 80
- 40 CFR 79
- 40 CFR 2
- 40 CFR 9
- Pub. L. 104-4
- Pub. L. 104-113
- 1 CFR 51
- 40 CFR 80.84
- 40 CFR 32
- 40 CFR 80.1165
- 40 CFR 80.1167
- 40 CFR 141
- 40 CFR 141.2
- Pub. L. 109-58
- 40 CFR 60
- 40 CFR 63
- 40 CFR 414
- 40 CFR 80.2(u)
- 40 CFR 79.55(e)(1)
- 636 F.2d 323
- 40 CFR 51
- 472 F.3d 882
- 42 USC 7401-7671q
- 24 CFR 983
- 37 CFR 380
- 37 CFR 351
- 37 CFR 353
- Pub. L. 104-39
- 109 Stat. 336
- Pub. L. 105-304
- 112 Stat. 2860
- 37 CFR 261
- Pub. L. 108-419
- 118 Stat. 2341
- 37 CFR 370
- 37 CFR 262.3(d)(2)
- 37 CFR 262.3(c)
- 37 CFR 262.4
- Pub. L. 107-321
- 116 Stat. 2780
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