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Code · REGISTER · 2005-12-29 · Federal Energy Regulatory Commission, DOE · Notices

Notices. Notice of proposed rulemaking

38,554 words·~175 min read·/register/2005/12/29/05-24609

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BILLING CODE 6750-01-P DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 284 [Docket Nos. RM05-23-000 and AD04-11-000] Rate Regulation of Certain Underground Storage Facilities December 22, 2005. AGENCY: Federal Energy Regulatory Commission, DOE. ACTION: Notice of proposed rulemaking. SUMMARY: The Federal Energy Regulatory Commission (Commission) is proposing to amend its regulations to establish criteria for obtaining market-based rates for storage services offered under part 284.
First, the Commission is proposing to modify its market-power analysis to better reflect the competitive alternatives to storage. Second, pursuant to Title III, Subtitle B, section 312 of the Energy Policy Act of 2005, the Commission is proposing rules to implement new section 4(f) of the Natural Gas Act, to permit underground natural gas storage service providers that are unable to show that they lack market power to negotiate market-based rates in circumstances where market-based rates are in the public interest and necessary to encourage the construction of the storage capacity in the area needing storage services, and that customers are adequately protected.
These revisions are intended to facilitate the development of new natural gas storage capacity while protecting customers. DATES: Comments are due February 27, 2006. ADDRESSES: Comments may be filed electronically via the eFiling link on the Commission's Web site at *http://www.ferc.gov* . Commenters unable to file comments electronically must send an original and 14 copies of their comments to: Federal Energy Regulatory Commission, Office of the Secretary, 888 First Street, NE., Washington, DC, 20426.
Refer to the Comment Procedures section of the preamble for additional information on how to file comments. FOR FURTHER INFORMATION CONTACT: Sandra Delude, Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426,
(202)502-8583. Michael Henry, Office of General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426,
(202)502-8532. Ed Murrell, Office of Markets, Tariffs, and Rates, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426,
(202)502-8703. Berne Mosley, Office of Energy Projects, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426,
(202)502-8625. SUPPLEMENTARY INFORMATION: I. Introduction 1. On August 8, 2005, the Energy Policy Act of 2005 (EPAct 2005 or the Act) 1 was signed into law. Section 312 of EPAct 2005, adding a new section 4(f) to the Natural Gas Act (NGA), 2 permits the Commission to allow a natural gas storage service provider placing new facilities in service to negotiate market-based rates even if it is unable to show that it lacks market power if the Commission determines that market-based rates are in the public interest and necessary to encourage the construction of the storage capacity in the area needing storage services, and that customers are adequately protected. 3 1 Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594 (2005). 2 15 U.S.C. 717, *et seq.* (2000). 3 Energy Policy Act of 2005, Pub. L. 109-58, § 312, 119 Stat. 594, 688 (2005). 2. The enactment of EPAct 2005 adds momentum to efforts already underway at the Commission to adopt policy reforms that would encourage the development of new natural gas storage facilities while continuing to protect consumers from the exercise of market power. On September 30, 2004, the Commission issued a staff report that examined underground natural gas storage. 4 On October 21, 2004, the Commission held a public conference with representatives of the industry to discuss the Staff Storage Report and issues relevant to underground storage. 5 The Commission received oral and written comments in connection with the Staff Storage Report and conference. 4 *Current State of and Issues Concerning Underground Natural Gas Storage, FERC Staff Report* , Docket No. AD04-11-000 (Sept. 30, 2004) (Staff Storage Report). 5 *State of the Natural Gas Industry Conference* , Docket No. PL04-17-000, October 21, 2004; *see* State of Natural Gas Industry Conference; Staff Report on Natural Gas Storage; Notice of Public Conference, 69 FR 59917 (Oct. 6, 2004) (summarizing the issues to be discussed at the conference). 3. After considering the conference comments, the current characteristics of the storage market, the nation's existing and projected storage capacity needs, and the new legislation, the Commission concludes that reform of its current pricing policies may be appropriate. The purpose of this reform is to ensure access to storage services on a nondiscriminatory basis at just and reasonable rates and ensure that sufficient storage capacity will be available to meet anticipated increases in market demand. To achieve these goals, the Commission is adopting a two-prong approach. First, this notice of proposed rulemaking
(NOPR)proposes modifications to the Commission's market power analysis to permit the consideration of close substitutes to storage in defining the relevant product market. This will ensure that market-based rates are not denied because of an overly narrow definition of the relevant market. Second, the Commission is proposing regulations to implement section 312 of EPAct 2005, which permits qualifying storage providers to charge market-based rates for a new facility even when they cannot (or do not) demonstrate that they lack market power. The Commission seeks comment, among other things, on whether there are certain generic safeguards that will provide adequate customer protections for entities applying for market-based rates under new NGA section 4(f). It should be noted, however, that these two policy reforms do not require a “sequential” approach for a potential storage developer. Instead, where a prospective applicant believes that it can make a showing sufficient to satisfy the requirements of new NGA section 4(f), it need not submit a traditional market power analysis in support of its request for market rates. In reviewing the applicant's request for market-based rates under section 4(f), the Commission will presume that the applicant has market power for the purposes of ensuring that customers are adequately protected. Taken together, the intent of these reforms is to facilitate the expansion of gas storage capacity to, among other things, mitigate natural gas price volatility, while continuing to protect consumers from the exercise of market power. II. Background A. Changing Nature of Storage Services 4. In Order No. 636, the Commission found that pipelines held a competitive advantage over other gas sellers, in part because of the lack of access to storage services. 6 Therefore, the Commission amended § 284.1(a) of its regulations to define transportation to include storage. This required pipelines to offer their customers firm and interruptible storage on an open-access, contract basis. Since the 1992 issuance of Order No. 636, much has changed. Storage is now being used to support new services made possible by the unbundling of storage from transportation and by new market conditions arising from the Commission's restructuring efforts. In addition, traditional interstate natural gas pipelines are experiencing competition for contract storage customers from independent storage providers. Many new entities provide myriad service options, and natural gas customers are able to choose among competing sellers, often as supplements or alternatives to “backstop” long-term, firm transportation and storage services contracted at Commission-regulated rates. 6 *Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation; and Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol* , 57 FR 13267 (Apr. 16, 1992), III FERC Stats. & Regs. ¶ 30,939 at 30,425-427 (Apr. 8, 1992), *order on reh'g* , Order No. 636-A, 57 FR 36128 (Aug. 12, 1992), III FERC Stats. & Regs. ¶ 30,950 (Aug. 3, 1992), *order on reh'g* , Order No. 636-B, 57 FR 57911 (Dec. 8, 1992), 61 FERC ¶ 61,272 (1992), *notice of denial of reh'g* , 62 FERC ¶ 61,007 (1993), *aff'd in part and vacated and remanded in part, United Dist. Companies* v. *FERC* , 88 F.3d 1105 (D.C. Cir. 1996), *order on remand* , Order No. 636-C, 78 FERC ¶ 61,186 (1997). 5. The nature of the gas storage marketplace also has changed significantly over the last decade. Traditionally, local distribution companies
(LDCs)contracted for firm storage service on a long-term basis, principally to meet peak winter heating needs. Thus, underground storage fields were typically designed to inject gas during the spring, summer, and fall, and then draw on the accumulated underground inventory to meet winter heating demands. This model is changing. Instead of relying primarily on firm, long-term gas supply or transportation service contracts, wholesale customers are increasingly relying on a portfolio of both long-term and short-term contracts to purchase, store and transport natural gas. 7 There is a growing use of storage volumes not only to meet traditional winter heating demand, but also to supply gas to meet daily, or even hourly, demand for gas-fired electric generation plants. Storage is also being used to ensure liquidity at market centers to help market participants capture short-term changes in the value of natural gas. 7 The development of a short-term market for gas services was addressed by the Commission in 2000, in its *Regulation of Short-Term Natural Gas Transportation Services and Regulation of Interstate Natural Gas Transportation Services* , Order No. 637, FERC Stats. & Regs. Regulations Preambles (July 1996—December 2000) ¶ 31,091 (Feb. 9, 2000), *order on reh'g* , Order No. 637-A, FERC Stats. & Regs. Regulations Preambles (July 1996-December 2000) ¶ 31,099 (May 19, 2000), *reh'g denied* , Order No. 637-B, 92 FERC ¶ 61,062 (2000), *aff'd in part and denied in part, Interstate Natural Gas Association of America* v. *FERC* , 285 F.3d 18 (D.C. Cir. 2002). In that proceeding, the Commission considered the consequences of the restructuring of the gas industry following Order No. 636, and found “a short-term gas market that is robust, functioning, efficient, and effective.” FERC Stats. & Regs. Regulations Preambles (July 1996-December 2000) ¶ 31,091 at 31,255 (Feb. 9, 2000) (quoting comments submitted by the New York Mercantile Exchange). 6. This fundamental shift in contract terms and load profile challenges longstanding operational and financial presumptions regarding storage service. Whereas a storage facility designed for one annual injection-withdrawal cycle is well suited to supply gas to meet winter heating demands, such a facility may be less than ideal in meeting the intermittent summer demand spikes associated with supplying gas to fuel electric generation plants. A storage facility capable of cycling working gas repeatedly throughout the year, using high deliverability and injection to fulfill daily, even hourly, swings in demand, such as salt cavern storage, is able to satisfy such load profiles. 8 However, electric generators are much less likely to sign traditional long-term firm contracts, but may be more interested in the type of flexible pricing proposals offered uniquely under market-based rates. 9 8 The Commission has authorized a number of salt cavern storage facilities that have these operational characteristics. See, *e.g.* , *Pine Prairie Energy Center, LLC* , 109 FERC ¶ 61,215
(2004)(authorizing the construction and operation of a high deliverability salt-cavern storage facility capable of as many as 30 injection-withdrawal cycles a year at maximum injection and withdrawal rates). 9 *See* , *e.g.* , Energy Information Administration, *The Challenge of Electric Power Restructuring for Fuel Suppliers* , at 54-56 (September 1998). B. Storage Capacity and Natural Gas Prices 7. Regardless of whether a storage facility is operated on a traditional, annual injection-withdrawal cycle, or completes multiple cycles throughout a year, the fact that gas can be injected into a storage facility and then held in repose, to be called upon during periods of high demand, has a moderating influence on gas prices. As a physical hedge, customers can build up underground inventories during times of lower demand, and then rely on these supply stores to avoid paying high spot market gas prices. Among the key findings highlighted by the Staff Storage Report is that the “continued commodity price volatility indicates that more storage may be appropriate” and that storage “may be the best way of managing gas commodity price, so the long-term adequacy of storage investment depends on how much price volatility customers consider ‘acceptable.’ ” 10 The last several years have seen a marked rise in the overall commodity cost of natural gas and sharp swings in gas prices. In view of the resulting adverse economic impacts, Commission policy should not discourage the development of additional storage capacity through overly narrow definitions of the relevant market. Furthermore, we should consider a range of customer protections in implementing our new authority under NGA section 4(f). 10 Staff Storage Report, at 1 (Sept. 30, 2004). C. The Need for Additional Storage 8. Currently, there are approximately 200 storage facilities subject to the Commission's jurisdiction, with an aggregate working gas capacity of approximately 2.5 Tcf. Estimates of total domestic working gas capacity (both subject to and exempt from NGA jurisdiction) range up to 4.7 Tcf. 11 Considering future storage needs of the United States and Canada together, the National Petroleum Council
(NPC)estimates an additional 700 Bcf will be required by 2025. 12 Although current and projected storage development is keeping pace with aggregate national storage demands, underground storage development in some market areas, such as New England 13 and the Southwest, is not. 14 11 The Department of Energy's Energy Information Administration
(EIA)reports that in 2002 working gas storage capacity varied between 4.4 and 4.7 Tcf, whereas the Department of Energy's Office of Fossil Energy reports that in 2003 there were 415 underground storage facilities with a working gas capacity of 3.9 Tcf. The Staff Storage Report considered the range of estimated aggregate existing working gas and concluded that the present working gas capacity is 3.5 Tcf, of which 2.5 Tcf is subject to NGA jurisdiction, and that by improving existing storage reservoirs ( *i.e.* , by reengineering existing facilities to enhance efficiency, rather than by expanding cavern capacity), there is the potential to obtain another 200 to 500 Bcf. *See* Staff Storage Report at 7-10. 12 *Balancing Natural Gas Policy—Fueling the Demands of a Growing Economy* , NPC, Volume II at 261 (2003). 13 New England appears to have little geologic potential for the development of underground storage facilities. 14 *See* , *e.g.* , Southwestern Gas Storage Technical Conference, Docket No. AD03-11-000, Transcript at 23, lines 10-14 (Aug. 26, 2003). 9. In large part, a storage facility's utility is a function of its location. Gas-fired electric generation is anticipated to drive a significant portion of the growth in gas consumption. Electric demand is expected to grow along with population, and one region of recent and forecasted population growth is the desert Southwest. 15 Since electric generation requirements are more transient than steady-state demand, base-load infrastructure facilities may not be an ideal means to meet future electric needs. Storage projects, especially high-deliverability salt cavern facilities, may prove more adaptable than pipelines in supplying gas on an as-needed basis to match the fluctuations in the demand profile of electric generation facilities. 15 For example, Arizona's population is expected to increase by 5.6 million by 2030. U.S. Census Bureau, Population Division, Interim Projections (April 2005). 10. Over the last several years, there has been a revival of interest in expanding existing and building new marine terminal facilities to import liquefied natural gas (LNG). New storage projects are being developed to absorb the additional revaporized LNG imports. To date, most such activity has been in the states along the arc of the Gulf of Mexico. The natural gas production, gathering, processing, transportation, and storage infrastructure in this region is extensive. Storage project sponsors have been able to demonstrate that the competitive nature of the gas market in this region ensures that new storage entrants are unlikely to be able to exercise market power, and hence merit market-based rates for new storage services. 16 In contrast, in the Southwest there is no equivalent infrastructure in place. This is noteworthy because several new LNG terminals are planned for the Mexican states of Baja California, Sonora, and Sinaloa, and a significant portion of the LNG received in Mexico is expected to flow north for consumption in the United States, with the Southwest as a targeted market. Additional storage in the Southwest could facilitate the receipt and distribution of these new natural gas supplies. 16 *See, e.g.* , *Caledonia Energy Partners, L.L.C.* , 111 FERC ¶ 61,095
(2005)and *Freebird Gas Storage, LLC* , 111 FERC ¶ 61,054
(2005)(approving new storage projects in the Gulf of Mexico area that qualified for market-based rates). 11. The development of underground storage facilities is dictated
(1)by geology, which determines the physical properties of prospective reservoirs, such as size and cushion gas requirements;
(2)by access to supply;
(3)by access to consuming markets; and
(4)by access to pipelines capable of transporting additional volumes of stored gas. Once a suitable site is identified, whether new storage capacity will be built turns on matters of construction and operating costs, market demand and the environment. Severe, adverse and unavoidable environmental impacts may preclude construction in certain locations. Investors also may be reluctant to fund a new project because of unattractive risk/reward prospects due to regulatory pricing constraints. This NOPR seeks to ensure that the Commission's regulatory approach does not unnecessarily impede the development of needed storage projects. 12. For storage services used on a short-term or spot basis, cost-of-service rates designed on the basis of an annual working gas cycle may not match up with the market value of storage service during transient periods of peak demand. Cost-of-service rates are based on projections of annual revenue requirements and relatively constant levels of demand. However, in today's markets, wholesale customers are not always willing to enter into long-term storage contracts sufficient to assure the storage investors that their annual revenue requirements will be met. Storage services used on a short-term or spot basis often do not exhibit the level of demand assumed by cost-of-service rate design. Permitting storage operators to earn higher revenues from short-term services during peak demand periods or through other pricing mechanisms may make an investment in the project economically feasible. Therefore, the NOPR seeks to lead to increased storage capacity that could benefit customers while continuing to protect them from the exercise of market power. III. Discussion 13. This NOPR is proposing changes to our regulations to permit storage providers to secure market-based rates under certain circumstances, while at the same time seeking to protect customers against potential exercises of market power. First, we are proposing regulations permitting all companies with storage facilities to seek market-based rates through a showing that their storage operations do not have significant market power. We have re-examined our approach to analyzing market power so that our analysis of whether to permit market-based rates for storage services better reflects the current competitive realities of the storage market. Second, for new storage capacity related to a specific facility placed into service after August 8, 2005, we are proposing regulations under new NGA section 4(f) that will authorize market-based rates under certain circumstances. Under these regulations, storage operators will be required to propose measures to protect customers from the potential exercise of market power, and we solicit comment on various approaches that could be used as generic safeguards in providing such protection. A storage service provider may apply for market-based rates under either method by filing appropriate supporting data when it files its certificate application, or as part of its request for NGPA section 311 rate authorization, or in a request for declaratory order for authority to charge market-based rates, but in any case it cannot charge market-based rates until the Commission concludes that the storage applicant has established that it lacks significant market power 17 or that it will adopt adequate customer protections pursuant to new NGA section 4(f). 17 *See Alternatives to Traditional Cost-of-Service Ratemaking for Natural Gas Pipelines* , 74 FERC ¶ 61,076 at 61,236 (1996), *reh'g and clarification denied* , 75 FERC ¶ 61,024 (1996), *petitions denied and dismissed, Burlington Resources Oil & Gas Co.* v. *FERC* , 172 F.3d 918 (D.C. Cir. 1998); *see also Association of Oil Pipe Lines* v. *FERC* , 83 F.3d 1424, 1442-43 (D.C. Cir. 1996). 14. The Commission recognizes that the measures proposed herein will not guarantee the proliferation of new storage projects. For example, despite a perceived need for new storage in the Southwest, there have been proposals for new storage projects that have failed to go forward for reasons unrelated to rate treatment. 18 Nevertheless, the flexibility proposed herein may induce the development of new storage capacity that would otherwise not be built. 18 See, for example, *Desert Crossing Gas Storage and Transportation System LLC* , 98 FERC ¶ 61,277 (2002), a proposal that has stalled, apparently due to shortfalls in contractual commitments and environmental concerns, and *Copper Eagle Gas Storage L.L.C.* , 97 FERC ¶ 62,193
(2001)and 99 FERC ¶ 61,270 (2002), a proposal delayed due to expressions of concern by the State of Arizona legislature raised as a result of security and safety issues associated with the project's planned location near Luke Air Force Base. A. Market Power Analysis for Market-Based Rates 15. The Commission evaluates requests to charge market-based rates for storage services under the analytical framework of its 1996 Alternative Rate Policy Statement (Policy Statement). 19 The Policy Statement establishes procedures for service providers to demonstrate that they lack significant market power, using criteria recognized by the courts and similar to those used by the Department of Justice and the Federal Trade Commission. Under the Policy Statement, an applicant seeking authority to charge market-based rates must demonstrate that it lacks significant market power, or has adopted conditions that sufficiently mitigate its market power. 20 19 *Alternatives to Traditional Cost-of-Service Ratemaking for Natural Gas Pipelines and Regulation of Negotiated Transportation Services of Natural Gas Pipelines* , 74 FERC ¶ 61,076 (1996), *reh'g and clarification denied* , 75 FERC ¶ 61,024 (1996), *petitions denied and dismissed, Burlington Resources Oil & Gas Co.* v. *FERC* , 172 F.3d 918 (D.C. Cir. 1998). 20 The Policy Statement describes significant market power as the ability to withhold services in a relevant market in order to produce a significant price increase for a significant period of time. The Commission adopted 10 percent as its standard price change threshold but did not preclude parties from arguing for the adoption of a higher or lower threshold in individual cases. 74 FERC ¶ 61,076 at 61,232. 16. The first step in analyzing whether an applicant has significant market power involves defining the relevant market in terms of both product market and geographic market. Such markets are defined by identifying the specific products or services and the suppliers of those products or services that provide good alternatives to the applicant's products and services. A good alternative is one that is available soon enough, has a price that is low enough, and has a quality high enough to permit customers to substitute the alternative for the applicant's services. 17. The Commission's initial screening tool for significant market power is the Herfindahl-Hirschman Index (HHI), a formula that focuses on the relevant market's concentration as an indicator of the potential of an applicant to act together with other sellers to raise prices. In general, an HHI below 1,800 suggests limited market concentration with less potential for any participant to exercise significant market power. However, an HHI above 1,800 suggests a higher level of concentration, and will cause the Commission to increase its scrutiny of other factors such as the applicant's market share, ease of entry into the market, the relative size of the applicant's capacity, and/or the sustainability of a potential attempt by the applicant to exercise market power. 21 21 *Id.* 18. Since 1996, over 40 storage service providers have sought market-based rates pursuant to the criteria in the Policy Statement. In the majority of these cases, the Commission found that the applicant lacked significant market power and approved market-based rates. In applying its market concentration and market share screens in these cases to date, the Commission has looked only to the availability of other storage alternatives (in the relevant geographic market), in assessing whether a storage provider can exercise significant market power. Using this analysis, the Commission has approved all requests for market-based rates where the applicant was located in the production area. Due to extensive storage infrastructure in these regions, the Commission has been able to find a lack of significant market power based on findings that HHIs in that geographic region are well below 1,800, and without intense scrutiny of other factors. 22 22 *See* , *e.g.* , *Caledonia Energy Partners, L.L.C.* , 111 FERC ¶ 61, 095 (2005); *Egan Hub Partners, L.P.* , 99 FERC ¶ 61,269 (2002); *Egan Hub Partners, L.P.* , 95 FERC ¶ 61,395 (2001). 19. On the other hand, storage markets in consuming regions, such as the Northeast portion of the United States, have fewer storage providers, and have certain providers with large market shares, resulting in HHI values sufficient to require a higher level of Commission scrutiny of factors beyond market concentration. Nevertheless, the Commission has approved requests in consuming areas of the Northeast by considering factors other than market concentration. For example, in *Avoca Natural Gas Storage* , 23 the Commission approved market-based rates despite an HHI for deliverability of 4,100 in the relevant New York/Pennsylvania market, specifically noting the small size of Avoca's market share and the apparent ease of entry into the market as factors mitigating the market concentration reflected in the HHI. 24 23 68 FERC ¶ 61,045 (1994). 24 The Commission reached a similar result analyzing storage services in *Steuben Gas Storage Co.* , 72 FERC ¶ 61,102 (1994); *New York State Electric and Gas Corp.* , 81 FERC ¶ 61,020 (1997); *N.E. Hub Partners, L.P.* , 83 FERC ¶ 61,043 (1998); *Seneca Lake Storage, Inc.* , 98 FERC ¶ 61,163 (2002); and *Wyckoff Gas Storage Co., LLC* , 105 FERC ¶ 61,027 (2003). 20. However, in areas where there are truly only a limited number of storage service providers, the Commission's traditional analysis will likely result in a storage provider having high HHI values as well as relatively large market shares. For example, in 2002, Red Lake Gas Storage, L.P. (Red Lake) proposed to construct a new underground storage facility in Arizona, an area not currently served by underground gas storage, and sought approval to charge market-based rates. The Commission denied Red Lake's market-based rate request based on its determination that, if built, the market Red Lake would operate in would be extremely concentrated and it would have substantial market power. 25 25 *Red Lake Gas Storage, L.P.* , 102 FERC ¶ 61,077, *reg'h denied* , 103 FERC ¶ 61,277 (2003). 21. The Commission is concerned that its current approach to analyzing market power may be too limiting in some circumstances because it does not consider the fact that non-storage products and services in a properly defined geographic market may be good alternatives to storage services, and thus mitigate a storage provider's ability to exercise market power. For example, in today's natural gas markets, pipeline capacity that is unaffiliated with the storage provider may be a good alternative to the storage service being offered. A new entrant proposing to offer its storage services in an area already fully served by existing pipelines would offer customers in that market area new service options, which to some extent would compete with existing service providers. Any new independent storage capacity would be expected to lower the market concentration and increase available alternatives in such a market. 22. The Commission therefore believes that it is not appropriate to limit the relevant product market to services offered by competing storage facilities. Such a narrow definition may incorrectly indicate that the storage applicant can exercise significant market power when, in fact, such ability could be constrained by sufficient pipeline alternatives. The denial of market-based rate authority in these circumstances could harm customers by providing a disincentive to storage development, particularly in underserved areas, in situations where significant market power does not exist. 1. Modifications to Market-Based Rate Test 23. The Commission proposes to reform its market-power test for natural gas storage operators to more accurately reflect the competitive conditions in the market for gas storage services. The Commission believes it is appropriate to adopt a more expansive definition of the relevant product market for storage to explicitly include close substitutes for gas storage services. We will evaluate potential substitutes, such as available pipeline capacity, and local gas production or LNG terminals, on a case-by-case basis in the context of individual applications for market-based rates 26 26 Historically, market area storage was often developed to provide an economic alternative to more expensive pipeline expansions. By design, market area storage service used available off-peak pipeline capacity to inject gas into storage and expanded pipeline capacity from the storage fields to markets to deliver incremental supplies during market peaks. Thus, storage plus limited pipeline expansions provided a good economical alternative to more expensive production-area-to-market-area pipeline expansions. 24. In order to show that a non-storage product or service such as transportation is a good alternative, the storage applicant would need to meet the criteria set forth in the Commission's Policy Statement, 27 including a showing that the service is available. In addition, consistent with the Commission's current practice, capacity on pipeline systems owned or controlled by the applicant's affiliates should not be considered among the customers' alternatives. Rather, affiliated capacity will be included in the market share calculated for the applicant. 28 27 A good alternative is one that is available soon enough, has a price that is low enough, and has a quality high enough to permit customers to substitute the alternative for the applicant's services. 28 *See* Policy Statement, 74 FERC ¶ 61,076 at 61,234 (1996). 25. We provide the following guidance regarding the types of products that may be close substitutes depending on the facts of a given case. As a general matter, competition to a storage provider can come from entities that have the ability to deliver gas in the same market as the storage facility. In producing areas, storage may compete with production or LNG supply, in addition to other storage facilities. In market areas, there may also be local production or LNG available. In addition, available pipeline capacity can function as a close substitute by delivering gas at peak times to compete with a storage provider. For these reasons, we will permit applicants to present evidence that both available pipeline capacity and local production/LNG supply in the geographic market area can reasonably be considered as alternative products to storage services. 26. In addition, firm capacity available through capacity release can be a good alternative in appropriate circumstances. Under the Commission's capacity release regulations, holders of firm capacity are free to release the capacity to other shippers, as well as to make bundled sales at alternate delivery points. Because of this flexibility, some portion of firm, contracted-for capacity may have a sufficiently elastic demand (a willingness to re-sell firm capacity when price rises) to serve as a good alternative to an applicant's storage service. 27. A determination of whether capacity release provides a close substitute will depend on the facts of a particular case. For example, to the extent an LDC or similar entity holds pipeline capacity that is needed to meet state-mandated service obligations for captive retail customers, the capacity holder may have a relatively inelastic demand that makes it unlikely that the LDC will release that capacity and therefore that increment of transportation capacity may not be considered a good alternative during peak periods. However, LDCs and marketers also serve industrial and other customers under interruptible contracts which might make that portion of the LDC's capacity a reasonable alternative. 28. Moreover, in some circumstances, an applicant may be able to show that even when firm capacity on a pipeline is reserved for captive customers, *e.g.* , residential and small commercial customers, potential product or service substitution in downstream markets can result in capacity becoming available to compete in upstream markets while still serving captive customers. Under the Commission's open-access program, competition in a downstream market may create competition in upstream markets, particularly due to Order No. 636's requirement that pipelines provide flexible receipt and delivery points and segmentation including backhaul. Thus, an LDC's ability to buy capacity from another pipeline or storage facility or to purchase gas in the downstream market may free it to release upstream capacity, to compete with storage in the upstream market. This ability to buy capacity from another pipeline or storage facility or buy gas in the market area is present in the large downstream markets in the United States including California, Chicago and the Northeast. 29. Take, for example, the California downstream market. Capacity held on Transwestern Pipeline Company, LLC (Transwestern) and El Paso Natural Gas Company (El Paso) could compete with a storage project located in a market upstream of California if California customers of these pipelines can buy gas from other sources in the downstream markets. This could free upstream capacity to compete with the upstream storage project. For example, Pacific Gas & Electric Company (PG&E) could buy gas from PG&E Gas Transmission, Northwest Corporation (PGT), Kern River Gas Transmission Company, an electricity generator in the California market, withdraw from its own storage, or purchase local production or regasified LNG to serve its captive or core customers. As a result, PG&E would be able to either release a portion of its firm capacity on El Paso, or nominate a secondary delivery at an upstream point to sell gas in the upstream market. As indicated above, whether capacity release in a given market would qualify as a close substitute under the Policy Statement would be determined on the facts of a given case. 30. Thus, based upon a proper showing, the Commission believes it would be appropriate for a storage applicant to include pipeline capacity that is used to serve captive customers if it is demonstrated that there are reasonable substitutes in the downstream market for serving load that would free up capacity in the upstream market that would compete with the storage project. 31. In summary, the Commission proposes to modify its current approach to analyzing market power to explicitly permit a storage applicant to propose to include other storage services, as well as non-storage products and services, including pipeline capacity and local production/LNG supply as described above, in its calculation of market concentration using the HHI and in its analysis of market share. The Commission believes that consideration of these alternative products will ensure that the Commission's market power analysis accurately reflects whether a storage applicant is able to exercise significant market power. The Commission requests comments on this approach as well as suggestions regarding other approaches for quantifying the amount of pipeline capacity that would compete with an applicant's storage services. 2. Filing Procedures and Periodic Review 32. Because most of the applications requesting market-based rates have been filed by storage providers, the Commission believes it would be beneficial to adopt specific procedures and filing requirements. Therefore, the Commission proposes to add a new subpart M to part 284 that requires, among other things, that applications by storage providers requesting market-based rates contain certain information. The Commission will continue its practice of approving market-based rate proposals on a prospective basis only. 33. Approval of blanket certificate authority to provide open access storage services at market-based rates will subject the storage service provider to the existing reporting requirements applicable to open-access service providers under § 284.13 of the Commission's regulations. The public disclosure of this information will enable the Commission and the industry to monitor the market-based storage transactions. 34. In a recent case, the Commission also required an applicant to file an updated market-power analysis within five years of the date of the Commission order granting authority to charge market-based rates, and every five years thereafter. 29 The Commission believes that imposition of a periodic review is necessary to ensure that our grant of market-based rates to an applicant remains just and reasonable. Accordingly, the Commission proposes to add § 284.504 to the regulations to require storage applicants receiving market-based rates on the basis of a market power analysis to file updated market-power analyses within five years of the date of the Commission order granting authority to charge market-based rates, and every five years thereafter. 29 *Liberty Gas Storage LLC* , 113 FERC ¶ 61,247 (2005). B. Energy Policy Act of 2005 35. Section 312 of EPAct 2005 adds new NGA section 4(f), which permits the Commission to authorize new natural gas storage projects ( *i.e.* , projects placed in service after the passage of the Act) to provide service at market-based rates notwithstanding the fact that the applicant is unable to demonstrate that it lacks market power. New NGA section 4(f) requires that, to authorize market-based rates, the Commission must find that “market-based rates are in the public interest and necessary to encourage the construction of the storage capacity in the area needing storage services” and “customers are adequately protected.” The Act further requires that the Commission “ensure that reasonable terms and conditions are in place to protect consumers” and that the Commission “review periodically whether the market-based rate is just, reasonable, and not unduly discriminatory or preferential.” Intrastate pipelines also provide storage services, and new NGA section 4(f)(1) extends the market-based rate authority to intrastate pipelines subject to Commission authority under the Natural Gas Policy Act of 1978. 30 We discuss below the relevant aspects of new NGA section 4(f). 30 15 U.S.C. 3301-3432 (2000). We note that the Commission has authorized Hinshaw pipelines to be treated the same as LDCs and we intend the same here. *See Certain Transportation, Sales and Assignments by Pipeline Companies not Subject to Commission Jurisdiction Under Section 1(c) of the Natural Gas Act, Order No. 63* , FERC Stats. & Regs. Regulations Preambles (1997-1981) ¶ 30,118 (Jan. 9, 1980). 1. Storage Capacity Eligible for Market-Based Rates 36. Under the new NGA section 4(f), the Commission may authorize market-based rates “for new storage capacity related to a specific facility placed in service after the date of enactment.” Interstate natural gas pipelines asked the Commission at the October 12, 2005 Conference on State of Natural Gas Infrastructure to allow post-EPAct 2005 storage expansions of existing storage facilities to qualify under this provision. 31 31 Comments of Scott Parker, President, Kinder Morgan Pipeline Group, State of the Natural Gas Infrastructure Conference, Docket No. AD05-14-000, Transcript at 120, lines 6-11 (Oct. 12, 2005). 37. We believe that the phrase “placed in service after the date of enactment” modifies the term “facility,” not the term “capacity,” such that it is the facility which must be placed into service after August 8, 2005, rather than the storage capacity. While the statute does not define the term “specific facility,” the Commission proposes to interpret that term to consider a new cavern, reservoir or aquifer that is developed after August 8, 2005, as a facility qualifying for market-based rates under the Act. We believe that this interpretation is most consistent with the wording of new NGA section 4(f). We invite comments on alternative constructions of the Act. We also invite comments on how, if we construe the Act differently, the Commission may adequately protect other customers already receiving service under cost-based authorizations that pre-date the Commission's new NGA section 4(f) authority. 2. Market-Based Rates Are in the Public Interest and Necessary To Encourage the Construction of Storage Capacity in the Area Needing Storage Services 38. Before authorizing market-based rates under new NGA section 4(f), the Commission is required to determine that such rates are in the public interest and are necessary to encourage the construction of storage capacity in the area needing storage services. As discussed in the section below, applicants for authorization under section 4(f) will be required to demonstrate that customers will be adequately protected from any abuses of market power by the storage provider. Those customer protections will serve to ensure that the market-based rates charged are in the public interest. 39. The Commission proposes to require that the applicant bear the burden of showing that in its specific circumstances, market-based rates are necessary to encourage the construction of storage capacity and that storage services are needed in the area. The Commission invites comment on how a project applicant might make these showings. One possible way would be for the applicant to present evidence that it offered its capacity at cost-based rates through an open season and was unable to obtain sufficient long-term commitments at those cost-based rates. 3. Customer Protection 40. New NGA section 4(f) also requires that the Commission, as a prerequisite for granting market-based rate authority, determine that customers are adequately protected, and requires the Commission to ensure that reasonable terms and conditions are in place to protect them. The Commission proposes to allow the applicant to propose a relevant method of protecting customers. 41. In general, the Commission believes that customers will be better off if more storage infrastructure is built. Additional storage will benefit customers by increasing customer alternatives in a market and by mitigating price volatility. 32 Therefore, just as the Commission balances the benefits of proposed new construction against residual adverse impacts in determining need under the Certificate Policy Statement, the Commission proposes, in considering requests for market-based rate authority under new NGA section 4(f), to balance the obvious benefits of additional storage capacity in areas needing storage services against any adverse impacts which might arise from the potential exercise of market power by the storage provider. The Commission is concerned that to the extent unnecessary conditions are imposed, the additional storage infrastructure and the additional service options they create would be lost to the detriment of potential customers. Accordingly, the Commission seeks comment on methods of customer protection which will allow it to achieve the desired balance. 32 *See Pine Prairie Energy Center, LLC* , 109 FERC ¶ 61,215 at P 21 (2004). 42. The appropriate method of customer protection may well vary depending on the facts and circumstances of individual project proposals. Thus, the Commission proposes to allow each applicant to propose a method of protecting customers best suited to its project. However, the Commission seeks comments on whether it would be beneficial to identify in this rulemaking certain acceptable approaches. Establishment of generic safeguards would facilitate the application process for NGA section 4(f) market-based rate authority. Each applicant, however, would retain the right to propose another method of protecting customers that might better fit the circumstances of its project. The Commission seeks suggestions of possible generic safeguards, as well as comments on the methods described below. 43. Entities with market power can exercise that power in two general areas:
(1)The withholding of capacity; and
(2)the extraction of monopoly rents. Thus, there are two approaches to protecting customers against the exercise of market power:
(i)Conditions that limit the withholding of capacity and
(ii)rate protections. We seek comment on whether there are generic safeguards in either method that would fairly balance the interests of consumers with the economic considerations relevant to financing new storage projects. As a general matter, we favor customer protections that are clear, easy to implement and oversee, and provide certainty to an applicant that is sufficient to support financing of a storage project. 44. One approach to customer protection is restrictions on withholding capacity. Market power can be exercised in those circumstances where a storage operator can withhold capacity from the market and raise prices. As long as storage capacity has not been withheld, “the fact that shippers may at times bid up contract length likely reflects not an exercise of [the pipeline's] market power, but rather competition for scarce capacity.” 33 We seek comment whether by ensuring that the storage operator has sold or made available to the market all of its capacity (and thus it is not withholding capacity), customers can be assured that market power is not being exercised by the storage service provider and that any increase in price is due to customers' demand for storage relative to the available supply. 34 33 *Process Gas Consumers Group* v. *FERC,* 292 F.3d 831, 837 (D.C. Cir. 2002). 34 *Id.* (affirming Commission determination that prices determined through an uncapped bidding process were the product of competitive forces, not the exercise of market power.) 45. A difficulty in applying this standard is in defining when withholding should be found to be indicative of the exercise of market power. The Commission requests comment on how to apply a prohibition against withholding which balances the competing needs of the project sponsor to secure revenues adequate to attract necessary investment in new infrastructure and of the needs of customers to be protected from the abuse of market power. For example, would allowing the storage operator to set a reserve price provide an appropriate balance? Should the withholding prohibition apply all the time, or only during periods of peak demand for storage services? If the Commission were to allow such conditions, how should terms such as “reserve price” (a minimum price below which the storage operator is not required to sell capacity) and “period of peak demand” be defined? 35 Should a formal auction process under which the applicant is obligated to sell all capacity above a reserve price be considered? 35 The Commission has long recognized that open access pipelines are not required to sell capacity at rates below the maximum cost-based rate. This form of withholding balances the pipeline's right to compensatory rates against the customer protections required by the Natural Gas Act. However, under market-based rates there is no clear point at which these conflicting interests may be easily balanced. 46. Market power can be exercised in those circumstances where a storage operator can extract monopoly rents. Rate protections could take several forms. For example, rate caps could be designed to provide adequate customer protection while also supporting the financing of new storage projects. We seek comment on whether there are certain approaches to rate caps that could be adopted as a generic safeguard. As another example, the Commission could allow an applicant to establish a long-term ( *e.g.* , 5-10 years) recourse rate that was cost-based and allow the applicant to negotiate contracts under market-based rates for shorter-term transactions. Would this approach be sufficient to protect customers without imposing an undue burden on the financing of new storage projects? Are there other cost-based rate designs or price cap methodologies that the Commission should consider to be generally acceptable if proposed by an applicant under this program? 4. Periodic Review 47. New NGA section 4(f) also requires that, for those entities granted market-based rates under this authority, the Commission “review periodically whether the market-based rate is just, reasonable, and not unduly discriminatory or preferential.” 48. The Commission believes that to encourage the construction of new storage infrastructure, it must balance the benefits of the additional options new storage will bring to wholesale customers against the burdens of various forms of periodic review. Certain forms of periodic reviews may deter applicants from pursuing projects by introducing an unnecessary element of regulatory uncertainty. Should this happen, additional storage infrastructure and the additional service options it creates would be lost to the detriment of wholesale customers. 49. For market-based rates approved under NGA section 4(f), the Commission believes that the periodic review requirement should focus on the consumer protection safeguards adopted and ensure that these safeguards are working as intended and effectively preventing the storage provider from exercising significant market power. In the Commission's view, an effective approach of complying with the periodic review requirement is through regular monitoring and taking appropriate action under section 5 of the NGA either sua sponte or in response to a complaint. In cases where the consumer protection requirements imposed prohibit withholding, the Commission believes the existing § 284.13 posting requirements and storage reports combined with publicly available information regularly reviewed by Staff are sufficient for this purpose. These require that interstate storage operators post information about transactions and available capacity, and require the submission of quarterly index of customers' reports, and submission of semi-annual storage reports to the Commission. Those storage operators providing service only under NGPA section 311 are subject to fewer reporting requirements set forth in § 284.126, which requires an annual transaction report, and a semi-annual storage report. 50. Therefore, existing posting requirements on contractual obligations, including prices charged, and levels of available capacity should provide the information for monitoring whether storage operators have been exercising market power by withholding. This information is currently required of all open-access transporters and storage operators. Should concerns be raised about the practices of any storage provider charging market-based rates authorized by this Commission, this information along with more specific information required during the course of any necessary inquiry in a specific case will provide the Commission with the information needed to ensure that rates conform to the statutory requirement. Similarly, the Commission believes that the lesser burden imposed on NGPA section 311 storage providers, which are primarily regulated by state authorities, is also adequate for this purpose. The Commission believes this monitoring approach adequately complies with the periodic review requirement in NGA section 4(f). 51. The Commission requests comment on this approach and whether this type of periodic review should be enhanced by other reporting or transparency requirements. Comments should discuss with specificity how other requirements might be imposed without unduly deterring needed new storage infrastructure investment. Moreover, the Commission seeks comment on whether the applicant should be required to demonstrate the continued adequacy of its existing customer protections every five years. Additionally, in cases where the Commission adopts customer protection safeguards other than withholding, the Commission intends to consider whether additional reporting is necessary to effectively monitor and review whether the market-based rate is just and reasonable. 52. The Commission, therefore, proposes to revise its part 284 regulations as follows. New subpart M will be added, which addresses applications for market-based rates for storage. Within new subpart M, § 284.501, Applicability, explains which pipelines or storage service providers are eligible to apply for market-based rates under subpart M, § 284.502, Procedures for applying for market-based rates, explains what procedures must be followed for submitting an application. Section 284.503, Market-power determination, explains what must be submitted as part of an application for market-based rates, including what information must be submitted related to an applicant's market power. Section 284.504, Periodic review for market power determinations, requires the filing of updated market-power analyses by storage providers granted the authority to charge market-based rates every five years. Section 284.505, Market-based rates for storage providers without a market-power determination, explains what a storage service provider that does not seek a market-power determination must submit to the Commission in an application for market-based rates. IV. Information Collection Statement 53. The Office of Management and Budget
(OMB)regulations require that OMB approve certain reporting, record keeping, and public disclosure (collections of information) imposed by an agency. 36 Accordingly, pursuant to OMB regulations, the Commission is providing notice of its proposed information collections to OMB for review under section 3507(d) of the Paperwork Reduction Act of 1995. 37 36 5 CFR 1320.11 (2005). 37 44 U.S.C. 3507(d) (2000). 54. The Commission identifies the information provided under Part 284 subpart M as contained in FERC-545, FERC-546 and FERC-549. 55. Comments are solicited on the Commission's need for this information, whether the information will have practical utility, the accuracy of the provided burden estimates, ways to enhance the quality, utility, and clarity of the information to be collected, and any suggested methods for minimizing respondent's burden, including the use of automated information techniques. 56. The burden estimates for complying with additional filing requirements of this rule pursuant to the procedures in proposed new sections 284.503 and 284.505 are set forth below. For the most part, the burden on applicants seeking market-based rates for open-access storage services will not be changed by this proposed rule. Since 1996, applications for authority to charge market-based rates have been filed under the Commission's procedures applicable to NGA section 7 initial rate determinations, NGA section 4 rate changes, or NGPA section 311 rate determinations under the Commission's existing data collection authorities. This rule codifies application procedures and filing requirements which are little changed from the process followed since 1996. Codification of filing requirements will allow applicants to know what information must be filed with such an application and should reduce the need for staff to send out follow-up data requests and respondents to file data responses. To the extent respondents seek market-based rate authority under the new NGA section 4(f) authorization process, also codified in these regulations, the burdens may be lower than if they had filed to seek authorization under the Commission's 1996 Policy Statement. On average, we expect the burden of making an application for authority to charge market-based rates under this proposed rule to be 350 hours. 57. Applicants granted market-based rate approval after the effective date of a final rule will also be required pursuant to proposed new § 284.504 to file an updated market power analysis once every five years. The burden of this requirement will be imposed on all who operate under market-based rate authorizations granted on the basis of a market power determination. On average, we expect the burden of filing an updated market power analysis under this proposed rule to be 350 hours, imposed once every five years. 58. Over the past several years the Commission has approved market-based rates for storage services at an average pace of about 4.5 per year. The Commission is issuing this proposed rule in hopes that more storage will be constructed and operated, especially in underserved areas. In reflection of this policy goal, the Commission estimates that up to 10 filings may be made in a typical year. While this estimate may be high, in light of recent experience, at worst the Commission is overestimating the burden. Data collection Number of respondents Number of responses per respondent Hours per response Total annual hours FERC-545, FERC-546, or FERC-549 10 1 350 3,500 *Total Annual Hours for Collection:* 3,500 hours. 59. *Information Collection Costs:* The Commission seeks comments on the cost to comply with these requirements. It has projected the average annualized cost for all respondents to be $280,000 (3,500 hours x $80.00 per hour). 60. *Title:* Gas Pipeline Rates: Rate Change (FERC-545); Certificated Rate Filings: Gas Pipeline Rates (FERC-546); and Gas Pipeline Rates: NGPA Title III Transactions (FERC-549). 61. *Action:* Proposed Information Collection. 62. *OMB Control Nos.:* 1902-0154, 1902-0155 and 1902-0086 63. The applicant shall not be penalized for failure to respond to these collections of information unless the collections of information display valid OMB control numbers. 64. *Respondents:* Business or other for profit. 65. *Frequency of Responses:* On occasion. 66. *Necessity of Information:* On August 8, 2005, Congress enacted EPAct 2005. Section 312 of EPAct 2005 amends the NGA to insert a new section, 4(f), which allows the Commission to permit natural gas storage service providers authority to charge market-based rates, subject to conditions and requirements set forth in the statute. The Commission considers the issuance of these regulations necessary to implement this Congressional mandate and to encourage the development of new natural gas storage facilities. The proposed rule updates the Commission's market power analysis to better reflect the competitive alternatives to storage available in today's wholesale natural gas marketplace. These changes should ease the applicant's burden in showing that a Commission grant of market-based rate authority is appropriate, thus encouraging the construction and operation of needed new storage infrastructure. While the new requirement for respondents to file an update of its market power analysis imposes a modest new burden, this will allow the Commission to ensure that customers will be protected from abuse of market power. In addition, the proposed rule in implementing EPAct 2005 creates regulations that allow qualifying storage providers to seek authority to charge market-based rates when the providers cannot or do not demonstrate they lack market power. The proposed rule revises the requirements contained in 18 CFR Part 284 to add a new subpart M to require that applications by storage providers requesting market-based rates contain certain information including a method for protecting customers and a showing of why market-based rates are necessary to encourage storage services. 67. *Internal Review:* The Commission has assured itself, by means of internal review, that there is specific, objective support for the burden estimates associated with the information requirements. The Commission staff will review the data included in the application to determine whether the proposed rates are in the public interest as well as for general industry oversight. Evidence establishing that market-based rates are necessary to encourage the construction of storage capacity is sufficient to also demonstrate that market-based rates are in the public interest. The Commission staff will review periodically the transactional and operational information provided by those granted authority to charge market-based rates pursuant to NGA section 4(f) to determine “whether the market-based rate is just, reasonable, and not unduly discriminatory or preferential.” These requirements conform to the Commission's plan for efficient information collection, communication and management within the natural gas industry. 68. Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426 (Attention: Michael Miller, Office of the Executive Director, 202-502-8415, fax: 202-273-0873, e-mail: *michael.miller@ferc.gov* ). 69. For submitting comments concerning the collection of information and the associated burden estimate(s) including suggestions for reducing this burden, please send your comments to the contact listed above and to the Office of Management and Budget, Room 10202 NEOB, 725 17th Street, NW., Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission, 202-395-4650, fax: 202-395-7285). V. Environmental Analysis 70. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment. 38 The Commission has categorically excluded certain actions from these requirements as not having a significant effect on the human environment. 39 The actions proposed to be taken here fall within categorical exclusions in the Commission's regulations for rules that are clarifying, corrective, or procedural, for information gathering, analysis, and dissemination, and for sales, exchange, and transportation of natural gas that requires no construction of facilities. 40 Therefore, an environmental review is unnecessary and has not been prepared in this rulemaking. We note that environmental review will be prepared in each proceeding in which an applicant requests authority to construct facilities that might become subject to the rate-setting requirements of this rule. 38 Order No. 486, Regulations Implementing the National Environmental Policy Act, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. Preambles 1986-1990 ¶ 30,783 (1987). 39 18 CFR 380.4 (2005). 40 *See* 18 CFR 380.4(a)(2)(ii), 380.4(a)(5), 380.4(a)(27) (2005). VI. Regulatory Flexibility Act Certification 71. The Regulatory Flexibility Act of 1980
(RFA)41 generally requires a description and analysis of the impact the proposed rule will have on small entities or a certification that the proposed rule will not have significant economic impact on a substantial number of small entities. However, the RFA does not define “significant” or “substantial” instead leaving it up to an agency to determine the impacts of its regulations on small entities. In determining the impacts, the RFA proposes that agencies consider alternatives that are less burdensome to small entities and an explanation of why an alternative was rejected. The RFA provides four examples of alternatives including tiering, classification and simplification, performance rather than design standards, and exemptions or waivers. The Small Business size classification standard for natural gas storage operators is that their revenues are not in excess of $6 million per year. 42 In the Commission's experience, it has found that the smallest entity applying for a market-based storage application had projected revenues that exceeded the SBA standard. Agencies are not required to make such an analysis if a rule would not have a significant adverse impact on a substantial number of small entities. The Commission does not believe that this proposed rule would have such an effect on small business entities, since the proposed amendments to our regulations would apply only to natural gas companies, most of which are not small businesses. However, should a small entity believe that this rule will have a significant impact on them, they may apply to the Commission for a waiver. Accordingly, pursuant to section 605(b) of the RFA, the Commission proposes to certify that the regulations proposed herein will not have a significant adverse impact on a substantial number of small entities. 41 5 U.S.C. 601-612. 42 *http://www.sba.gov/size/sizetable2002.html* . VII. Comment Procedures 72. The Commission invites interested persons to submit comments on the matters and issues proposed in this notice to be adopted, including any related matters or alternative proposals that commenters may wish to discuss. Comments are due February 27, 2006. Comments must refer to Docket Nos. RM05-23-000 and AD04-11-000, and must include the commenter's name, the organization they represent, if applicable, and their address in their comments. Comments may be filed either in electronic or paper format. 73. Comments may be filed electronically via the eFiling link on the Commission's Web site at *http://www.ferc.gov.* The Commission accepts most standard word processing formats and commenters may attach additional files with supporting information in certain other file formats. Commenters filing electronically do not need to make a paper filing. Commenters that are not able to file comments electronically must send an original and 14 copies of their comments to: Federal Energy Regulatory Commission, Office of the Secretary, 888 First Street, NE., Washington, DC 20426. 74. All comments will be placed in the Commission's public files and may be viewed, printed, or downloaded remotely as described in the Document Availability section below. Commenters on this proposal are not required to serve copies of their comments on other commenters. VIII. Document Availability 75. In addition to publishing the full text of this document in the **Federal Register** , the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through FERC's Home Page ( *http://www.ferc.gov* ) and in FERC's Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A, Washington DC 20426. 76. From FERC's Home Page on the Internet, this information is available in the Commission's document management system, elibrary. The full text of this document is available on elibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in elibrary, type the docket number excluding the last three digits of this document in the docket number field. 77. User assistance is available for elibrary and the FERC's website during normal business hours. For assistance, please contact FERC Online Support at 1-866-208-3676 (toll free) or 202-502-6652 (e-mail at *FERCOnlineSupport@ferc.gov* ), or the Public Reference Room at 202-502-8371, TTY 202-502-8659 (e-mail at *public.referenceroom@ferc.gov.* List of Subjects in 18 CFR Part 284 Continental shelf, Incorporation by reference, Natural gas, Reporting and recordkeeping requirements. By direction of the Commission. Magalie R. Salas, Secretary. In consideration of the foregoing, the Commission proposes to amend part 284, Chapter I, Title 18, Code of Federal Regulations, as set forth below. PART 284—CERTAIN SALES AND TRANSPORTATION OF NATURAL GAS UNDER THE NATURAL GAS POLICY ACT OF 1978 AND RELATED AUTHORITIES 1. The authority citation for part 284 continues to read as follows: Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7352; 43 U.S.C 1331-1356. 2. New subpart M is added to read as follows: Subpart M—Applications for Market-Based Rates for Storage Sec. 284.501 Applicability. 284.502 Procedures for applying for market-based rates. 284.503 Market power determination. 284.504 Periodic review requirement for market power determinations. 284.505 Market-based rates for storage providers without a market-power determination. § 284.501 Applicability. Any pipeline or storage service provider that provides or will provide service under subparts B, C, and G of this part, and that wishes to provide storage and storage-related services at market-based rates must conform to the requirements in subpart M. § 284.502 Procedures for applying for market-based rates.
(a)Applications for market-based rates may be filed with certificate applications. Service, notice, intervention, and protest procedures for such filings will conform with those applicable to the certificate application.
(b)With respect to applications not filed as part of certificate applications,
(1)Applicants providing service under subpart B or subpart G of this part must file a request for declaratory order and comply with the service and filing requirements of part 154 of this chapter. Interventions and protest to applications for market-based rates must be filed within 30 days of the application unless the notice issued by the Commission provides otherwise.
(2)Applicants providing service under subpart C of this part must file in accordance with the requirements of that subpart.
(c)An applicant cannot charge market-based rates under this subpart of this part until its application has been accepted by the Commission. Once accepted, the applicant can make the appropriate filing necessary to set its market-based rates into effect. § 284.503 Market power determination. An applicant may apply for market-based rates by filing a request for a market power determination that complies with the following:
(a)The applicant must set forth its specific request and adequately demonstrate that it lacks market power in the market to be served, and must include an executive summary of its statement of position and a statement of material facts in addition to its complete statement of position. The statement of material facts must include citation to the supporting statements, exhibits, affidavits, and prepared testimony.
(b)The applicant must include with its application the following information:
(1)*Statement A—geographic market.* This statement must describe the geographic markets for storage services in which the applicant seeks to establish that it lacks significant market power. It must include the market related to the service for which it proposes to charge market-based rates. The statement must explain why the applicant's method for selecting the geographic markets is appropriate.
(2)*Statement B—product market.* This statement must identify the product market or markets for which the applicant seeks to establish that it lacks significant market power. The statement must explain why the particular product definition is appropriate.
(3)*Statement C—the applicant's facilities and services.* This statement must describe the applicant's own facilities and services, and those of all parent, subsidiary, or affiliated companies, in the relevant markets identified in Statements A and B in paragraphs
(1)and
(2)of this section. The statement must include all pertinent data about the storage facilities and services.
(4)*Statement D—competitive alternatives.* This statement must describe available alternatives in competition with the applicant in the relevant markets and other competition constraining the applicant's rates in those markets. Such proposed alternatives may include other storage, local gas supply, LNG, and pipeline capacity. These alternatives must be shown to be reasonably available as a substitute in the area to be served soon enough, at a price low enough, and with a quality high enough to be a reasonable alternative to the applicant's services. Available capacity (transportation, storage, LNG,or production) owned or controlled by affiliates of the applicant in the relevant market shall be clearly and fully identified and may not be considered as alternatives competing with the applicant. Rather, the capacity of an applicant's affiliates is to be included in the market share calculated for the applicant. To the extent available, the statement must include all pertinent data about storage or other alternatives and other constraining competition.
(5)*Statement E—potential competition.* This statement must describe potential competition in the relevant markets. To the extent available, the statement must include data about the potential competitors, including their costs, and their distance in miles from the applicant's facilities and major consuming markets. This statement must also describe any relevant barriers to entry and the applicant's assessment of whether ease of entry is an effective counter to attempts to exercise market power in the relevant markets.
(6)*Statement F—maps.* This statement must consist of maps showing the applicant's principal facilities, pipelines to which the applicant intends to interconnect and other pipelines within the area to be served, the direction of flow of each line, the location of the alternatives to the applicant's service offerings, including their distance in miles from the applicant's facility. The statement must include a general system map and maps by geographic markets. The information required by this statement may be on separate pages.
(7)*Statement G—market power measures.* This statement must set forth the calculation of the market concentration of the relevant markets using the Herfindahl-Hirschman Index. The statement must also set forth the applicant's market share, inclusive of affiliated service offerings, in the markets to be served. The statement must also set forth the calculation of other market power measures relied on by the applicant. The statement must include complete particulars about the applicant's calculations.
(8)*Statement H—other factors.* This statement must describe any other factors that bear on the issue of whether the applicant lacks significant market power in the relevant markets. The description must explain why those other factors are pertinent.
(9)*Statement I—prepared testimony.* This statement must include the proposed testimony in support of the application and will serve as the applicant's case-in-chief, if the Commission sets the application for hearing. The proposed witness must subscribe to the testimony and swear that all statements of fact contained in the proposed testimony are true and correct to the best of his or her knowledge, information, and belief. § 284.504 Periodic review requirement for market power determinations. Applicants granted the authority to charge market-based rates under § 284.503 are required to file an updated market-power analysis within five years of the date of the Commission order granting authority to charge market-based rates, and every five years thereafter. § 284.505 Market-based rates for storage providers without a market-power determination.
(a)Any storage service provider seeking market-based rates for storage capacity, pursuant to the authority of Section 4(f) of the Natural Gas Act, related to a specific facility put into service after August 8, 2005, may apply for market-based rates by complying with the following requirements:
(1)The storage service provider must demonstrate that market-based rates are necessary to encourage the construction of the storage capacity in the area needing storage services; and
(2)The storage service provider must provide a means of protecting customers from the potential exercise of market power.
(b)Any storage service provider seeking market-based rates for storage capacity pursuant to this section will be presumed by the Commission to have market power. [FR Doc. E5-8031 Filed 12-28-05; 8:45 am] BILLING CODE 6717-01-P DEPARTMENT OF THE INTERIOR National Park Service 36 CFR Part 7 RIN 1024-AD44 Cape Lookout National Seashore, Personal Watercraft Use AGENCY: National Park Service, Interior. ACTION: Proposed rule. SUMMARY: The National Park Service
(NPS)is proposing to designate areas where personal watercraft
(PWC)may be used in Cape Lookout National Seashore, North Carolina. This proposed rule implements the provisions of the NPS general regulations authorizing park areas to allow the use of PWC by promulgating a special regulation. The NPS Management Policies 2001 directs individual parks to determine whether PWC use is appropriate for a specific park area based on an evaluation of that area's enabling legislation, resources and values, other visitor uses, and overall management objectives. DATES: Comments must be received by February 27, 2006. ADDRESSES: You may submit comments, identified by the number RIN 1024-AD44, by any of the following methods: • Federal rulemaking portal: *http://www.regulations.gov* Follow the instructions for submitting comments. • Mail or hand delivery to: Superintendent, Cape Lookout National Seashore, 131 Charles Street, Harkers Island, NC 28531. • For additional information see “Public Participation” under SUPPLEMENTARY INFORMATION below. FOR FURTHER INFORMATION CONTACT: Jerry Case, Regulations Program Manager, National Park Service, 1849 C Street, NW., Room 7241, Washington, DC 20240. Phone:
(202)208-4206. E-mail: *jerry_case@nps.gov.* SUPPLEMENTARY INFORMATION: Background Additional Alternatives The information contained in this proposed rule supports implementation of portions of the preferred alternative in the Environmental Assessment
(EA)published January 2005. The public should be aware that two other alternatives were presented in the EA, including a no-PWC alternative, and those alternatives should also be reviewed and considered when making comments on this proposed rule. Personal Watercraft Regulation On March 21, 2000, the NPS published a regulation (36 CFR 3.24) on the management of PWC use within all units of the national park system (65 FR 15077). This regulation prohibits PWC use in all national park units unless the NPS determines that this type of water-based recreational activity is appropriate for the specific park unit based on the legislation establishing that park, the park's resources and values, other visitor uses of the area, and overall management objectives. The regulation banned PWC use in all park units effective April 20, 2000, except for 21 parks, lakeshores, seashores, and recreation areas. The regulation established a 2-year grace period following the final rule publication to provide these 21 park units time to consider whether PWC use should be permitted to continue. Description of Cape Lookout National Seashore Cape Lookout National Seashore was established by Congress in 1966 to conserve and preserve for public use and enjoyment the outstanding natural, cultural, and recreational values of a dynamic coastal barrier island environment for future generations. Cape Lookout National Seashore is a low, narrow, ribbon of sand located three miles off the mainland coast in the central coastal area of North Carolina and occupies more than 29,000 acres of land and water from Ocracoke Inlet on the northeast to Beaufort Inlet to the southwest. The national seashore consists of four main barrier islands (North Core Banks, Middle Core Banks, South Core Banks, and Shackleford Banks), which consist mostly of wide, bare beaches with low dunes covered by scattered grasses, flat grasslands bordered by dense vegetation, and large expanses of salt marsh alongside the sound. There are no road connections to the mainland or between the islands. Coastal barrier islands, such as those located in Cape Lookout National Seashore, are unique land forms that provide protection for diverse aquatic habitats and serve as the mainland's first line of defense against the impacts of severe coastal storms and erosion. Located at the interface of land and sea, the dominant physical factors responsible for shaping coastal landforms are tidal range, wave energy, and sediment supply from rivers and older, pre-existing coastal sand bodies. Relative changes in local sea level also profoundly affect coastal barrier island diversity. Coastal barrier islands exhibit the following six characteristics: • Subject to the impacts of coastal storms and sea level rise. • Buffer the mainland from the impact of storms. • Protect and maintain productive estuarine systems which support the nation's fishing and shellfishing industries. • Consist primarily of unconsolidated sediments. • Subject to wind, wave, and tidal energies. • Include associated landward aquatic habitats which the non-wetland portion of the coastal barrier island protects from direct wave attack. Coastal barrier islands protect the aquatic habitats between the barrier island and the mainland. Together with their adjacent wetland, marsh, estuarine, inlet, and nearshore water habitats, coastal barriers support a tremendous variety of organisms. Millions of fish, shellfish, birds, mammals, and other wildlife depend on barriers and their associated wetlands for vital feeding, spawning, nesting, nursery, and resting habitat. Shackleford Banks contains the park's most extensive maritime forest as well as wild horses that have adapted to this environment over the centuries. The islands are an excellent place to see birds, particularly during spring and fall migrations. A number of tern species, egrets, herons, and shorebirds nest here. Loggerhead turtles climb the beaches at nesting time. Purpose of Cape Lookout National Seashore Cape Lookout National Seashore was authorized on March 10, 1966, by Public Law 89-366. Additional legislation, Public Law 93-477 (October 26, 1974), called for another 232-acre tract of land to be acquired, a review and recommendation of any suitable lands for wilderness designation, and authorized funding for land acquisition and essential public facilities. The purpose of Cape Lookout National Seashore is to conserve and preserve for public use and enjoyment the outstanding natural, cultural, and recreational values of a dynamic coastal barrier island environment for future generations. The national seashore serves as both a refuge for wildlife and a pleasuring ground for the public, including developed visitor amenities. The mission of Cape Lookout National Seashore is to: • Conserve and preserve for the future the outstanding natural resources of a dynamic coastal barrier island system; • Protect and interpret the significant cultural resources of past and contemporary maritime history; • Provide for public education and enrichment through proactive interpretation and scientific study; and • Provide for sustainable use of recreation resources and opportunities. Significance of Cape Lookout National Seashore Cape Lookout National Seashore is nationally recognized as an outstanding example of a dynamic natural coastal barrier island system. Cape Lookout is designated as a unit of the Carolinian-South Atlantic Biosphere Reserve, United Nations Educational, Scientific and Cultural Organizations (UNESCO) Man and the Biosphere Reserve Program. The park contains: • Cultural resources rich in the maritime history of humankind's attempt to survive at the edge of the sea; and • Critical habitat for endangered and threatened species and other unique wildlife including the legislatively protected wild horses of Shackleford Banks. Authority and Jurisdiction Under the National Park Service's Organic Act of 1916 (Organic Act) (16 U.S.C. 1 *et seq.* ) Congress granted the NPS broad authority to regulate the use of the Federal areas known as national parks. In addition, the Organic Act (16 U.S.C. 3) allows the NPS, through the Secretary of the Interior, to “make and publish such rules and regulations as he may deem necessary or proper for the use and management of the parks * * *.” 16 U.S.C. 1a-1 states, “The authorization of activities shall be conducted in light of the high public value and integrity of the National Park System and shall not be exercised in derogation of the values and purposes for which these various areas have been established * * *.” The NPS's regulatory authority over waters subject to the jurisdiction of the United States, including navigable waters and areas within their ordinary reach, is based upon the Property Clause and, as with the United States Coast Guard's authority, Commerce Clause of the U.S. Constitution. In regard to the NPS, Congress in 1976 directed the NPS to “promulgate and enforce regulations concerning boating and other activities on or relating to waters within areas of the National Park System, including waters subject to the jurisdiction of the United States * * *.” (16 U.S.C. 1a-2(h)). In 1996 the NPS published a final rule (61 FR 35136 (July 5, 1996)) amending 36 CFR 1.2(a)(3) to clarify its authority to regulate activities within the National Park System boundaries occurring on waters subject to the jurisdiction of the United States. Motorboats and other watercraft have been in use at Cape Lookout National Seashore since the park was established in 1966. It is unknown when PWC use first began at the national seashore. In compliance with the settlement with the Bluewater Network, the national seashore closed to PWC use in April 2002. Personal watercraft are prohibited from launching or landing on any lands, boat ramps or docks within the boundaries of the national seashore. Personal watercraft may not be towed on trailers or carried on vehicles within national seashore boundaries except at the Harker's Island unit. This closure pertains to all of the barrier islands within the national seashore and the waters on the soundside of the islands within 150 feet of the mean low waterline. Outside of the park boundary, PWC use is governed by North Carolina PWC regulations. At present, the areas that were previously used by PWC owners for landing are closed with signs. Prior to the PWC closure, all areas of the park were open to PWC use. However, the majority of PWC use was concentrated in two areas of the national seashore that receive the heaviest visitor day-use in the park:
(1)On the sound-side of South Core Banks at the Lighthouse (from the Lighthouse dock through Barden Inlet and Lookout Bight), and
(2)the Shackleford Banks from Wade Shores west to Beaufort Inlet. Personal watercraft use of ocean beaches was rare due to rough surf conditions in the ocean and the hazard of beaching PWC in the ocean surf. Some PWC use occurred along North and South Core Banks from Portsmouth Village at the northern end of the national seashore to the lighthouse. This use was infrequent because of the prevalence of marshes and general lack of sound-side beaches along Core Banks, the large expanse of open water in Core Sound between the barrier islands and mainland North Carolina, and the low population of the adjacent communities in the “down east” as this portion of the national seashore is known locally. At public meetings held in October 2001, several participants indicated they had used their PWC to travel from locations such as Atlantic and Davis to the barrier islands. The popularity of Cape Lookout and Shackleford Banks where PWC use was concentrated can be attributed to the excellent soundside beaches in these areas, the attraction of the Cape Lookout lighthouse, traditional use of Shackleford Banks, their proximity to major inlets, and their close proximity to the three largest coastal population centers in Carteret County: Atlantic Beach, Morehead City, and Beaufort. Resource Protection and Public Use Issues Cape Lookout National Seashore Environmental Assessment As a companion document to this proposed rule, NPS has issued the Cape Lookout National Seashore, Personal Watercraft Use Environmental Assessment. The EA was open for public review and comment from January 24, 2005 to February 24, 2005. Copies of the EA may be downloaded at *http://www.nps.gov/calo/pphtml/documents.html* or requested by telephoning
(252)728-2250. Mail inquiries should be directed to park headquarters: Cape Lookout National Seashore, 131 Charles Street, Harkers Island, NC 28531. The purpose of the EA was to evaluate a range of alternatives and strategies for the management of PWC use at Cape Lookout National Seashore to ensure the protection of park resources and values while offering recreational opportunities as provided for in the National Seashore's enabling legislation, purpose, mission, and goals. The analysis assumed alternatives would be implemented beginning in 2003 and considered a 10-year period, from 2003 to 2013. The EA evaluates three alternatives concerning the use of PWC at Cape Lookout National Seashore. The alternatives considered include: • *No-Action Alternative:* Do not reinstate PWC use within the national seashore. No special regulation would be promulgated. • *Alternative A:* Reinstate PWC use as previously managed under a special regulation. • *Alternative B:* Reinstate PWC use under a special NPS regulation with additional management prescriptions. Based on the analysis prepared for PWC use at Cape Lookout National Seashore, alternative B is considered the environmentally preferred alternative because it would best fulfill park responsibilities as trustee of sensitive habitat; ensure safe, healthful, productive, and aesthetically and culturally pleasing surroundings; and attain a wider range of beneficial uses of the environment without degradation, risk of health or safety, or other undesirable and unintended consequences. This document proposes regulations to implement alternative B at Cape Lookout National Seashore. The NPS will consider the comments received on this proposal, as well as the comments received on the EA when making a final determination. In the final rule, the NPS will implement alternative B as proposed, or choose a different alternative or combination of alternatives. Therefore, the public should review and consider the other alternatives contained in the EA when making comments on this proposed rule. The following summarizes the predominant resource protection and public use issues associated with PWC use at Cape Lookout National Seashore. Each of these issues is analyzed in the *Cape Lookout National Seashore, Personal Watercraft Use Environmental Assessment.* Water Quality Most research on the effects of PWC on water quality focuses on the impacts of two-stroke engines generally, and it is assumed that any impacts caused by these engines also apply to two-stroke engines in PWC. Two-stroke engines (and PWC) discharge a gas-oil mixture into the water. Fuel used in PWC engines contains many hydrocarbons, including benzene, toluene, ethylbenzene, and xylene (collectively referred to as BTEX). Polycyclic aromatic hydrocarbons
(PAHs)also are released from boat engines, including those in PWC. These compounds are not found appreciably in the unburned fuel mixture, but rather are products of combustion. Discharges of all these compounds—BTEX and PAHs—have potential adverse effects on aquatic life and human health if present at high enough concentrations. A common gasoline additive, methyl tertiary butyl ether
(MTBE)is also released with the unburned portion of the gasoline. The PWC industry suggests that although some unburned fuel does enter the water, the fuel's gaseous state allows it to evaporate readily. A typical conventional (i.e., carbureted) two-stroke PWC engine discharges as much as 30% of the unburned fuel mixture into the exhaust. At common fuel consumption rates, an average two-hour ride on a PWC may discharge three gallons (11.34 liters) of fuel into the water. The Bluewater Network states that PWC can discharge between three and four gallons of fuel over the same time period. However, the newer four-stroke technology can reduce these emissions to meet current regulatory standards for both water and air quality. The percentage of emissions of BTEX and MTBE compounds from four-stroke inboard or outboard motors is less than those from a two-stroke outboard engine or an existing two-stroke PWC engine. Under the proposed regulation, based on alternative B in the EA, PWC use would be allowed within ten designated access areas, as identified in the “Alternatives” chapter of the EA and in the proposed rule. Personal watercraft within these access areas would be restricted to a perpendicular approach to the shoreline at flat-wake speed. Personal watercraft operation would be prohibited in park waters outside of the access areas. All state regulatory requirements would continue to apply. Because of the requirement for a perpendicular approach to the shoreline at flat-wake speed under this alternative, each PWC trip was assumed to be of only 5 minutes duration within park jurisdictional waters at 10% of full-throttle. The results of the water quality analysis for PWC activity (table 24 of the EA) shows that for all discharged pollutants evaluated, the ecotoxicological threshold volumes estimated for 2003 and 2013 would be well below volumes of water available at the study areas. Threshold volumes are less than an acre-foot, while water volumes in the park range from 3,890 to 6,810 acre-feet. Impacts on aquatic organisms would be expected to be negligible for all pollutants evaluated. Threshold volumes for human health benchmarks of benzo(a)pyrene and benzene estimated for 2003 and 2013 are also less than an acre-foot, which is well below volumes of water available in the study areas. Impacts on human health would be expected to be negligible for all pollutants evaluated. Mixing, flushing, and the resulting dilution of park waters by adjacent waters would further reduce pollutant concentrations. Tidal currents at Beaufort and Ocracoke inlets reach speeds of up to 4 knots. Incoming tides more than double the available water volume. Outgoing tides transport soluble pollutants out of park waters to the Atlantic Ocean. Overall, water quality impacts due to PWC emissions of organic pollutants in both 2003 and 2013 would be negligible. Cumulative impacts associated with the implementation of alternative B under the proposed regulation would result from the cumulative activities taking place around Cape Lookout, including other motorized watercraft that use nearby waters and point and non-point sources of urban pollutants. Based on 2003 observations, on a typical peak use day, motorized watercraft are assumed to be distributed as follows: 565 at Shackleford Banks, 380 at South Core Banks, and 20 at North Core Banks. Assuming a 1.6% average annual increase (except for ferries), non-PWC numbers would increase by 2013 to 640 at Shackleford Banks, 430 at South Core Banks, and 24 at North Core Banks. Threshold volumes calculated for all motorized watercraft are shown in table 25 of the EA. For all discharged pollutants evaluated, the ecotoxicological threshold volumes estimated for 2003 and 2013 would be well below volumes of water available in park jurisdictional waters in the study areas. Threshold volumes would be 37 acre-feet or less, while park jurisdictional water volumes range from 3,890 to 6,810 acre-feet. Impacts on aquatic organisms are expected to be negligible for all pollutants evaluated. Threshold volumes for risks to human health from benzo(a)pyrene and benzene would also be well below the jurisdictional volumes in all areas in 2003 and 2013. Threshold volumes would be 44 acre-feet or less, while park jurisdictional water volumes range from 3,890 to 6,810 acre-feet. Risks to human health from benzo(a)pyrene and benzene, largely attributable to non-PWC use, would be expected to be negligible for all areas in 2003 and 2013. Under the proposed regulation, water quality impacts from PWC use, based on ecotoxicological and human health benchmarks, would be negligible for all pollutants in all areas in both 2003 and 2013. Cumulative water quality impacts from all motorized watercraft under the proposed regulation, based on ecotoxicological benchmarks, would be negligible for all pollutants in all areas in both 2003 and 2013. Cumulative impacts on human health from all motorized watercraft would be negligible in 2003 and 2013. In 2013, cumulative water quality impacts from watercraft are expected to be lower than in 2003 due to reduced emission rates. Therefore, implementation of this proposed regulation would not result in an impairment of water quality. Air Quality Personal watercraft emit various compounds that pollute the air. Up to one third of the fuel delivered to the typical two-stroke carbureted PWC engine is unburned and discharged; the lubricating oil is used once and is expelled as part of the exhaust; and the combustion process results in emissions of air pollutants such as volatile organic compounds (VOC), nitrogen oxides (NO <sup>X</sup> ), particulate matter (PM), and carbon monoxide (CO). Personal watercraft also emit fuel components such as PAH that are known to cause adverse health effects. Even though PWC engine exhaust is usually routed below the waterline, a portion of the exhaust gases go into the air. These air pollutants may adversely impact park visitor and employee health as well as sensitive park resources. For example, in the presence of sunlight, VOC and NO <sup>X</sup> emissions combine to form ozone (O <sup>3</sup> ). O <sup>3</sup> causes respiratory problems in humans, including coughs, airway irritation, and chest pain during inhalations. O <sup>3</sup> is also toxic to sensitive species of vegetation. It causes visible foliar injury, decreases plant growth, and increases plant susceptibility to insects and disease. CO can affect humans as well. It interferes with the oxygen carrying capacity of blood, resulting in lack of oxygen to tissues. NO <sup>X</sup> and PM emissions associated with PWC use can degrade visibility. NO <sup>X</sup> can also contribute to acid deposition effects on plants, water, and soil. However, because emission estimates show that NO <sup>X</sup> from PWC are minimal (less than 5 tons per year), acid deposition effects attributable to PWC use are expected to be minimal. *Impacts to human health.* Under the proposed regulation, special use areas would be identified where PWC could access Shackleford Banks, South Core Banks, and North Core Banks. Personal watercraft access could only access the beach in these areas and approach only perpendicular to the beach at flat-wake speeds. Personal watercraft use and access would be prohibited in all other areas of the national seashore. Safety and operating restrictions would be dictated by the North Carolina PWC regulations outlined under alternative A and additional NPS operating restrictions. Human-health air quality impacts from the implementation of alternative B under this proposed regulation would be similar to those described for alternative A in the EA for 2003 and 2013 and would be negligible for CO, PM <sup>10</sup> , HC, and NO <sup>X</sup> . The human health risk from PAH would also be negligible in 2003 and 2013. The additional restrictions would not change the type of PWC in use, nor increase or decrease the number of PWC forecasted. Assuming that PWC are primarily used for transportation, the estimated daily duration of use of an individual PWC would decrease from 10 minutes under alternative A to 5 minutes under alternative B for both 2003 and 2013. Therefore, impacts would be negligible and at even lower levels than under alternative A. Under the proposed regulation, cumulative impacts to human health from all boating use in the national seashore would not change from alternative A. Adverse impacts on human health from air pollutants in 2003 would be negligible for CO, PM <sup>10</sup> , NO <sup>X</sup> , and HC. In 2013, levels would remain negligible for CO, PM <sup>10</sup> , NO <sup>X</sup> , and HC. Because no reduction in PWC use is expected, the proposed regulation would result in negligible air quality impacts on human health from PWC emissions, similar to alternative A. The additional management prescriptions would slightly reduce PWC emissions as compared with alternative A. Negligible adverse impacts from PWC emissions for CO, PM <sup>10</sup> , HC, and NO <sup>X</sup> would occur in 2003 and 2013. The risk from PAH would also be negligible in 2003 and 2013. Cumulative adverse impacts from PWC and other boating emissions at the national seashore would be the same as for alternative A. Adverse impacts on human health from air pollutants in 2003 would be negligible for CO, PM <sup>10</sup> , NO <sup>X</sup> , and HC. In 2013, levels would remain negligible for CO, PM <sup>10</sup> , NO <sup>X</sup> , and HC. Regional ozone emissions would improve due to a reduction in HC emissions. This proposed regulation would have negligible adverse impacts on human health air quality conditions, with future reductions in CO and HC emissions due to improved emission controls. The PWC contribution to emissions of HC is estimated to be less than 5% of the cumulative boating emissions in 2003 and 2013. All impacts would be long-term. Therefore, implementation of this proposed regulation would not result in an impairment of air quality as it relates to human health. *Impacts to air quality related values.* Under the proposed regulation, the annual number of PWC using the Cape Lookout National Seashore would be the same as alternative A. Additional management prescriptions under the proposed regulation, including the adoption of special use areas, would not affect PWC use numbers and potential future increases. The predicted emission levels and impacts of continued PWC use to air quality related values would be similar to those described for alternative A based on annual emission rates. Assuming that PWCs are primarily used for transportation, the estimated daily duration of PWC use of an individual PWC would decrease from 10 minutes under alternative A to 5 minutes under alternative B for both 2003 and 2013. Impacts on air quality related values from PWC in 2003 and 2013 would be negligible. Cumulative adverse impacts on air quality related values at the national seashore in both 2003 and 2013 would be the same as described under alternative A. HC contribution to ozone-related air quality values would be negligible. In 2013, NO <sup>X</sup> emissions would slightly increase but would remain well below 50 tons per year, and there would be a reduction in HC emissions, resulting in a reduced contribution to ozone levels relative to 2003. Predicted year 2013 regional SUM06 ozone levels would be in the same range as year 2003; the impact would remain negligible. The impacts of the proposed regulation on air quality related values would be the same as alternative A. Emissions of each pollutant would be substantially less than 50 tons per year in both 2003 and 2013. Negligible adverse impacts on air quality related values from PWC would occur in both 2003 and 2013. In both 2003 and 2013, adverse impacts from cumulative emissions from motorized boats and PWC would be negligible. This conclusion is based on calculated levels of pollutant emissions (table 31 of the EA), regional SUM06 values, and the lack of observed visibility impacts or ozone-related plant injury in the national seashore. Therefore, implementation of this proposed regulation would not result in an impairment of air quality related values. Soundscapes The primary soundscape issue relative to PWC use is that other visitors may perceive the sound made by PWC as an intrusion or nuisance, thereby disrupting their experiences. This disruption is generally short-term because PWC are generally used as transportation to and from the islands. However, if PWC use changed from mostly transport to more extended recreational riding or if PWC use would increase and concentrate at popular visitation areas, such as Shackleford Banks and the lighthouse, related noise would become more of an issue, particularly during certain times of the day. Additionally, visitor sensitivity to PWC noise varies from kayakers (more sensitive) to swimmers at popular beaches (less sensitive). Under the proposed regulation, PWC would be reinstated at Cape Lookout in specific locations. Personal watercraft would have access to areas that had been historically popular with PWC users; restrictions under this proposed regulation were based on safety reasons or the need to protect natural resources, particularly marshlands, which PWC avoid. However, all PWC operating within the special use areas defined under this proposed regulation would be required to operate at flat-wake speed within the national seashore's boundaries, which includes all waters from the mean low water line on the oceanside to 150 feet beyond the mean low water line. In addition, the area consisting predominantly of maritime forest along the soundside of Shackleford Banks would be closed to PWC use for safety reasons due to the high amount of visitor use in this area. Therefore, visitors using this area of Shackleford Banks would not experience adverse impacts because of the absence of PWC noise. Impacts throughout Shackleford Banks would be adverse, short-term, and minor. The flat-wake speed restrictions would also lessen adverse impacts in the waters adjacent to the Cape Lookout lighthouse and the northern areas of the national seashore. Personal watercraft would be permitted access at specific locations along Core Sound, which were historically used by PWC in the past. Because most of the Core Sound consists of marshlands, PWC use along the South and North Core Banks was low before the ban, even during summer holiday weekends. For these reasons, noise impacts in the national seashore's northern reaches would be adverse, short-term, but negligible. Combining PWC noise with other noise sources, such as other motorized vessels, beach activities, and off-road vehicle use, would increase the overall sound level at the national seashore. However, limiting PWC to flat-wake speed in all permitted areas of the national seashore would reduce adverse noise impacts considerably. Increased visitation expected to the Cape Lookout lighthouse would result in increased noise from both motorboats and PWC accessing this area. Therefore, cumulative impacts would be adverse, short-term, and negligible to minor under this proposed regulation, depending on location. Personal watercraft would be permitted in areas historically preferred by PWC users under this proposed regulation, but only at flat-wake speed, resulting in adverse, short-term, negligible to minor impacts, depending on location. Cumulative impacts would be adverse, short-term, and negligible to minor under this proposed regulation, depending on location. Therefore, implementation of this proposed regulation would not result in an impairment of the national seashore's soundscape. Shoreline and Submerged Aquatic Vegetation Personal watercraft are able to access areas that other types of watercraft may not, which may cause direct disturbance to vegetation. Indirect impact to shoreline vegetation may occur through trampling if operators disembark and engage in activities on shore. In addition, wakes created by PWC may affect shorelines through erosion by wave action. Personal watercraft are very maneuverable and can operate well in waters less than a foot deep. Since most PWC rides begin in shallow water, the process of getting started from a standstill results in a substantial amount of water being directed towards the bottom at high velocity, potentially disturbing the sediment and submerged aquatic vegetation in shallow water areas. Disturbance of submerged aquatic vegetation beds diminishes their ecological value and productivity, affecting the entire ecosystem. As PWC are frequently operated in shallow areas in a repetitive manner, impacts on submerged aquatic vegetation beds can be severe. Potential direct impacts on submerged aquatic vegetation beds by PWC can occur through collision, uprooting of submerged aquatic vegetation, and alteration of natural sediments. Potential indirect impacts of PWC use include adverse effects on the growth and health of submerged aquatic vegetation beds as a result of increased turbidity, decreased available sunlight, and deposition of suspended sediment on plants. Under this proposed regulation, PWC use would be allowed within 10 designated access areas, as identified in the “Alternatives” chapter of the EA and the proposed rule language. Personal watercraft operation within these access areas would be restricted to a perpendicular approach to the shoreline at flat-wake speed. Personal watercraft would be prohibited in park waters outside of the access areas. All state regulatory requirements would continue to apply. These 10 designated access areas were chosen to avoid marshes and high-congestion beach areas. Indirect impacts from PWC use to shoreline vegetation would occur but would be limited to the designated access areas and would therefore be negligible to minor and short-term. Impacts on shoreline vegetation associated with low salt marsh habitats would not occur, since PWC use would be restricted in these areas. As PWC would be prohibited in park waters outside of the access areas, submerged aquatic vegetation beds in these areas would not be directly impacted by PWC use. Most of the access areas do not contain submerged aquatic vegetation beds, so PWC operation in these areas would have little potential to adversely impact this habitat. Additionally, the flat-wake speed restriction would minimize the potential for PWC to damage submerged aquatic vegetation beds through collision or uprooting and would reduce sediment resuspension and its detrimental effects. Reinstating PWC use in park waters and restricting their operation to a flat-wake perpendicular approach to the shoreline in designated access areas would result in negligible, indirect short- and long-term impacts on submerged aquatic vegetation beds. Under this proposed regulation, PWC use would be limited to flat-wake speed within ten designated access areas, resulting in a negligible contribution to cumulative impacts on shoreline vegetation and submerged aquatic vegetation beds. Adverse direct and indirect cumulative effects associated with future increased use by motorized watercraft, including PWC, would be minor around landing areas and in tidal marsh habitats. Non-PWC motorized vessels would be able to operate throughout park waters, including areas where submerged aquatic vegetation beds occur. Potential direct impacts on submerged aquatic vegetation beds by all motorized vessels include propeller scarring, collision, uprooting, and sediment alteration. Potential indirect impacts include increased turbidity, decreased available sunlight, and suspended sediment deposition on submerged aquatic vegetation beds. However, both PWC and non-PWC trip lengths are short and speeds are low, which reduces the likelihood of adverse impacts. As PWC are outnumbered by non-PWC motorized vessels in park waters by more than 10 to 1, and most PWC use would not occur around submerged aquatic vegetation beds, nearly all impacts on shoreline vegetation and submerged aquatic vegetation beds would be attributed to non-PWC vessels. Impacts on shoreline vegetation and submerged aquatic vegetation beds from all types of motorized vessels under this proposed regulation are expected to be minor, direct and indirect, and short- and long-term. Reinstating PWC use in park waters and restricting their operation to a flat-wake perpendicular approach to the shoreline in designated access areas is expected to have negligible, indirect short-term impacts on submerged aquatic vegetation beds and negligible to minor short-term impacts on shoreline vegetation. Non-PWC vessels would still be able to access submerged aquatic vegetation beds under this alternative, and would be responsible for nearly all of the cumulative motorized vessel impacts on submerged aquatic vegetation beds. Motorized vessels, including PWC, are expected to have minor, direct and indirect, short- and long-term cumulative impacts on shoreline vegetation and submerged aquatic vegetation beds. Therefore, implementation of this proposed rule would not result in an impairment of shoreline vegetation and submerged aquatic vegetation beds. Wildlife and Wildlife Habitat Some research suggests that PWC use affects wildlife by causing interruption of normal activities, alarm or flight, avoidance or degradation of habitat, and effects on reproductive success. This is thought to be a result of a combination of PWC speed, noise, and ability to access sensitive areas, especially in shallow-water depths. Waterfowl and nesting birds are the most vulnerable to PWC. Fleeing a disturbance created by PWC may force birds to abandon eggs during crucial embryo development stages, prevent nest defense from predators, or contribute to stress and associated behavior changes. Potential impacts on sensitive species, such as loggerhead sea turtles and piping plover, are documented in the “Threatened, Endangered, or Special Concern Species” section. Aquatic wildlife react to high levels of underwater noise in various ways, depending on the species, exposure period, intensities, and frequencies. Because of the way PWC are used, noise is usually produced at various intensities, and this continual change in loudness during normal use makes PWC-generated noise much more disturbing than the constant sounds of conventional motorboats. The sudden increases in noise levels can startle aquatic wildlife, triggering flight responses. In areas of high boating use, the energy cost to aquatic fauna due to noise-induced stresses could be significant, potentially affecting their survival. Intense sounds can inflict pain and damage the sensory cells of the ears of mammalian species, and there is concern that similar sounds can impair hearing in aquatic wildlife species. One of the few direct studies on the impact of sound on fishes conducted under laboratory conditions found that when fish were subjected to high decibel levels for four hours, some sensory cells of the ears were damaged. This damage does not show up until a few days after exposure, and it is a short-term effect (regeneration did occur after a few days). Fish exposed to high decibel noise levels may have a short-term disadvantage in detecting predators and prey, potentially adversely affecting their survival. In addition, several species of fish in the drum family produce sounds as part of their mating behavior, so short-term hearing damage could negatively affect reproduction. Loggerhead turtle nesting has been shown to be negatively affected by loud noises such as close overflights by aircraft, but it is unknown at what frequencies and intensity noise might affect sea turtles or damage their hearing. Although marine mammals show a diverse behavioral range that can obscure correlations between a specific behavior and the impact from noise, experts from around the country have voiced concern that PWC activity can have negative impacts on marine mammals, disturbing normal rest, feeding, social interactions, and causing flight. Toothed whales (including dolphins), produce sounds across a broad range of frequencies for communication as well as echolocation, a process of creating an acoustic picture of their surroundings for the purpose of hunting and navigation. Watercraft engine noise can mask sounds that these animals might otherwise hear and use for critical life functions and can cause temporary hearing threshold shifts. Bottlenose dolphins exposed to less than an hour of continuous noise at 96 dB experienced a hearing threshold shift of 12 to 18 dB, which lasted hours after the noise terminated. A hearing threshold shift of this degree would substantially reduce a dolphin's echolocation and communication abilities. In 1998 C. Perry reviewed numerous scientific studies documenting increased swimming speed, avoidance, and increased respiration rates in whales and dolphins as a result of motorized watercraft noise. Whales have been observed to avoid man-made noise of 115 dB, and at higher frequencies, whales become frantic, their heart rates increase, and vocalization may cease. Bottlenose dolphins and manatees may be present in the waters surrounding Cape Lookout National Seashore in the summer months and could be affected by PWC-generated noise. Kemp's ridley, loggerhead, leatherback, and green sea turtles occur in the waters around Cape Lookout National Seashore, and three of these species have nested on park beaches. In addition, more than 200 species of fish probably occur in the waters surrounding Cape Lookout National Seashore. Essential fish habitat occurs in the vicinity of Cape Lookout for a number of commercially and recreationally important fish (refer to the “Aquatic Wildlife” section in the “Affected Environment” chapter of the EA). This proposed regulation would establish 10 special use areas to provide PWC access within the Cape Lookout National Seashore boundaries. Personal watercraft use would be prohibited in all other areas of the national seashore. Implementing flat-wake zones in these areas would limit adverse impacts on wildlife within the national seashore boundaries. Impacts of PWC use associated with noise and potential collision impacts with aquatic wildlife would be minimized within national seashore boundaries with the reduction of allowable speeds and adverse noise fluctuations. Negligible, short-term adverse indirect impacts on terrestrial and aquatic wildlife and habitat are expected under the proposed regulation, as noise would be reduced with the implementation of the flat-wake zone. In areas previously open to PWC use that are not within the 10 special use areas, adverse impacts would be eliminated or reduced as PWC noise would be eliminated from these areas and would not create a disturbance to wildlife and wildlife habitats. As PWC would be prohibited in park waters outside of the access areas, aquatic wildlife in these areas would not be impacted by PWC use. In the designated access areas, the PWC flat-wake speed requirement and perpendicular approach would not generate waves and would minimize sediment resuspension and damage to seagrass beds. The flat-wake speed limit would further minimize PWC engine noise and fuel emissions to water. Aquatic wildlife species inhabiting the shallow waters and seagrass beds within the access areas would experience negligible impacts from PWC operation. Reinstating PWC use in park waters and restricting their operation to a flat-wake perpendicular approach to the shoreline in designated access areas is expected to have short-term, negligible, direct and indirect adverse impacts on aquatic wildlife species and habitats. Under the proposed regulation, motorized vessels, including PWC, would have adverse impacts on aquatic wildlife and habitats in park waters, especially in high-use areas such as Shackleford Banks and Lookout Bight. Because non-PWC vessels vastly outnumber PWC in park waters, most cumulative boating impacts on aquatic wildlife would be caused by non-PWC vessels and would be similar to those described under alternative A. Restricting PWC to access areas and flat-wake speed would result in a negligible contribution to cumulative impacts. Cumulative impacts on dolphins, sea turtles, fish and shellfish, and their habitats from all motorized vessel use are expected to be short-term, minor, direct and indirect, and adverse. Impacts on terrestrial wildlife, specifically birds, from all motorized vessel use are expected to be short-term, negligible to minor, direct and indirect, and adverse. Noise levels and the ability of other motorized watercraft users to access Shackleford Banks and Lookout Bight are expected to adversely affect terrestrial wildlife and shorebirds and waterfowl that may utilize the landing area and adjacent areas by causing alarm or flight responses. Effects are expected to be negligible to minor because these areas have a generally high level of visitation, regardless of PWC usage, and species sensitive to a high level of noise and human activity would probably not regularly use these areas or immediately adjacent habitats during high use periods. The proposed regulation would minimize potential adverse impacts of PWC use in the 10 designated special use areas to negligible to minor, short-term, adverse impacts. The flat-wake requirements would reduce the level of PWC disturbance in the restricted areas and in nearby marshes. Reinstating PWC use in park waters and restricting their operation to a flat-wake perpendicular approach to the shoreline in designated access areas is expected to have short-term, negligible to minor, direct and indirect adverse impacts on terrestrial and aquatic wildlife species and habitats. Cumulative impacts associated with an increase in all types of motorized vessel use are expected to be short-term, negligible to minor, direct and indirect, and adverse. Therefore, implementation of this proposed regulation would not result in an impairment of terrestrial or aquatic wildlife or habitats in park waters. Threatened, Endangered, or Special Concern Species The Endangered Species Act (16 U.S.C. 1531 *et seq.* ) mandates that all federal agencies consider the potential effects of their actions on species listed as threatened or endangered. If the NPS determines that an action may adversely affect a federally listed species, consultation with the U.S. Fish and Wildlife Service is required to ensure that the action will not jeopardize the species' continued existence or result in the destruction or adverse modification of critical habitat. At Cape Lookout National Seashore it has been determined that none of the alternatives are likely to adversely affect any of the listed species that are known to occur or may occur within or adjacent to PWC activity within the boundaries of Cape Lookout National Seashore. National Park Service Management Policies 2001 state that potential effects of agency actions will also be considered on state or locally listed species. The NPS is required to control access to critical habitat of such species, and to perpetuate the natural distribution and abundance of these species and the ecosystems upon which they depend. The species at Cape Lookout National Seashore that have the potential to be affected by proposed PWC management alternatives include species that are known to inhabit or are likely to inhabit the area, plus those that could possibly be found in the area, but would most likely be transients or migrants. Under the proposed regulation, PWC use would be allowed within ten designated access areas, as identified in the “Alternatives” chapter of the EA and in the proposed rule language. Personal watercraft operation within these access areas would be restricted to a perpendicular approach to the shoreline at flat-wake speed. Personal watercraft operation would be prohibited in park waters outside of the access areas. All state regulatory requirements would continue to apply. This proposed regulation may affect, but is not likely to adversely affect, federally listed threatened or endangered terrestrial species in the Cape Lookout National Seashore. Effects to federally listed threatened or endangered species associated with PWC use under the proposed regulation would be similar to those discussed under alternative A. However, the potential for impacts would be further minimized due to reduced levels of activity and use. Enforcement of flat-wake zones in the ten designated special use areas would decrease potential for near-shore noise associated with the PWC use to adversely affect protected species such as the piping plover. As PWC operation would be prohibited in park waters outside of the access areas, aquatic special concern species in these areas would not be impacted by PWC use. Manatees and whales are not likely to be present in park waters during the summer when PWC use is high. Sea turtles and the Carolina diamondback terrapin are likely to be present in park waters during the summer. These turtles may be affected but are not likely to be adversely affected by PWC use under this proposed regulation, because most park waters would be off-limits to PWC and because the flat-wake speed restriction would further reduce the potential for collision, as well as reducing engine noise production and fuel discharge to water. Reinstating PWC use in park waters and restricting their operation to a flat-wake perpendicular approach to the shoreline in designated access areas may affect but is not likely to adversely affect aquatic special concern species. The majority of piping plover nests are located on North Core Banks, which accounted for 10 out of 14 nesting pairs in 2003. The majority of PWC activity occurs at Shackelford Banks and the lighthouse area at South Core Banks. Sea beach amaranth, piping plover nesting, and gull-billed tern nesting areas are all roped off where present. These species generally occur in areas of low PWC use, and PWC use may affect but is not likely to adversely affect these species. Under this proposed regulation, PWC use would be limited to flat-wake speed within designated access areas, resulting in a negligible contribution to cumulative impacts. Non-PWC motorized vessels would be able to operate throughout park waters. Because manatees are not common in the area and northern right whales and humpback whales are not likely to occur in park waters in the summer, PWC and other motorized watercraft use may affect but are not likely to adversely affect these species. As previously mentioned, trip lengths for PWC and non-PWC are short, and due to the park's very shallow waters, operation of these vessels primarily consists of slow speed operation. Because of these factors, PWC and non-PWC vessel use may affect but is not likely to adversely affect sea turtles or Carolina diamondback terrapins. Non-PWC vessels outnumber PWC in park waters by more than 10 to 1, so any motorized vessel impacts on special concern species would be predominantly attributed to non-PWC vessels. Due to the location of sensitive species and the areas of high PWC use and other motorized watercraft being typically separate, PWC use and other motorized watercraft may affect but are not likely to adversely affect special concern species. Reinstating PWC use in park waters and restricting their operation to a flat-wake perpendicular approach to the shoreline in designated access areas may affect but are not likely to adversely affect manatees or whales in park waters, as these species are not present in areas or during seasons of peak PWC use. Personal watercraft and other motorized vessel use may affect but is not likely to adversely affect sea turtles or Carolina diamondback terrapins because of the slow vessel speeds and short trip lengths. Therefore, implementation of this alternative would not result in an impairment of aquatic special concern species in park waters. Visitor Use and Experience Some research suggests that PWC use is viewed by some segments of the public as a nuisance due to their noise, speed, and overall environmental effects, while others believe that PWC are no different from other motorcraft and that people have a right to enjoy the sport. The primary concern involves changes in noise, pitch, and volume due to the way PWC are operated. Additionally, the sound of any watercraft can carry for long distances, especially on a calm day. Under this proposed regulation, PWC would have access to 10 areas distributed along the entire national seashore. These areas include those that were historically popular with PWC users, such as the Cape Lookout lighthouse area and the west end of Shackleford Banks. Fifty-one miles of the seashore's sound side and 56 miles of the oceanside would be closed to PWC use. Five of a total of 10 miles (50%) of soundside sandy beaches would be available to PWC use. *Impacts on PWC Users* . Personal watercraft users would experience beneficial impacts, as they would have access to those areas that were historically popular with PWC riders. Personal watercraft would be restricted from the marshlands along the Core Banks, which they avoided anyway for practical reasons. With the exception of the closed areas between the two toilet facilities on Shackleford Banks and those in the lighthouse area of South Core Banks, PWC would have access to many of the areas frequented by PWC prior to the ban. Therefore, benefits would be similar to having access to the entire national seashore, with the exception of the restricted area on Shackleford and near the lighthouse. Impacts would be beneficial, long-term, and minor since approximately only 1% of all visitors would be affected. *Impacts on Other Boaters* . Personal watercraft would return to popular areas such as the Cape Lookout lighthouse area and Shackleford Banks, with the exception of the restricted section. Under this proposed regulation, PWC users would be required to operate at flat-wake speed within park waters, providing a beneficial impact to all boaters, particularly kayakers and canoeists, who would be most affected by wakes and noise. Canoeists and kayakers paddling the marshlands along the Core Sound would experience negligible impacts from reinstated PWC use because PWC would be prohibited in marshland areas. Although some complaints have been submitted regarding PWC use in these areas, PWC have primarily avoided marshlands in the past. Boaters in the national seashore's northern reaches would experience few, if any, impacts, given the extremely low PWC use in this area in the past. Paddlers and motor boat operators using the west end of Shackleford near Beaufort Inlet or the Cape Lookout lighthouse area would experience the most adverse impacts due to congestion in these popular areas. Other motorized boat users would also interact with PWC, and may experience adverse impacts for similar reasons. However, motorized boat users may find PWC use more compatible with their type of recreation. Depending on location, overall impacts on other boaters would be adverse, short- and long-term, and negligible to minor due to flat-wake PWC speed restrictions in park waters. *Impacts on Other Non-PWC Users* . As with other boaters, other non-PWC users would experience benefits from flat-wake speed restrictions under this proposed regulation. The PWC restricted area along Shackleford Banks between the two toilet facilities would provide beneficial impacts on visitors in this area. A stretch of maritime forest fronts the sound in this restricted area, providing a natural, pristine wilderness setting that is popular with campers (Wade's Shore is located near the eastern toilet facility on Shackleford). Restricting PWC in this area would enhance wilderness values there, including preservation of the primeval character of the wilderness, natural conditions (including lack of man-made noise), outstanding opportunities for solitude, and a primitive recreational experience. Because most non-fishing visitors come to the national seashore seeking a remote beach experience, restricted PWC use under this alternative would provide a beneficial impact to these visitors. In addition, 89% of respondents during public scoping indicated that they were in favor of banning PWC from the national seashore. Therefore, a majority of visitors may perceive PWC use as incompatible with their experience at Cape Lookout National Seashore and would prefer restricted access, even though PWC represented only a small percentage of national seashore visitors. Restricting PWC within national seashore waters to flat-wake speed would also be particularly beneficial to swimmers, anglers, and beach combers, who may be more likely to experience adverse impacts from PWC use than motorized boat users. Short-term impacts on all visitors would occur depending on the duration of exposure to PWC during a given visit. Visitors would also experience long-term impacts in that PWC use would have restricted access to the national seashore indefinitely into the future. Cumulative impacts would be similar to those described under alternative A in the EA regarding an increase in motorized boaters accessing the Cape Lookout lighthouse starting in 2005. However, flat-wake speed restrictions under this alternative would provide a benefit in areas of increasing congestion. An increase in boaters in Barden Inlet, combined with restricted, reinstated PWC use, would result in an adverse impact in this area. Combining restricted PWC use with other motorized boat use would result in an adverse impact. Even though only 1% of visitors used PWC to access the national seashore in the past, impact levels would be moderate due to expected increases in visitation. Reinstating PWC use with restricted access would result in beneficial impacts on PWC users, but adverse, short- and long-term impacts on other boaters (motorized and nonmotorized) ranging from negligible to moderate depending on location and type of boat use. Cumulative impacts would be adverse, short- and long-term, and negligible due to the historically low numbers of PWC at the national seashore and additional PWC use restrictions. Visitor Conflict and Safety Industry representatives report that PWC accidents decreased in some states in the late 1990s. The National Transportation Safety Board reported that in 1996 PWC represented 7.5% of state-registered recreational boats but accounted for 36% of recreational boating accidents. In the same year PWC operators accounted for more than 41% of the people injured in boating accidents. Personal watercraft operators accounted for approximately 85% of the persons injured in accidents studied in 1997. Only one PWC-related injury has been reported at Cape Lookout National Seashore, although much of the waters in the area are outside of park boundaries and many incidents likely are not reported to any agency at all. The park currently does little or no water-based enforcement, which would be necessary to better identify PWC/visitor safety issues. Very few PWC violations have been documented by national seashore staff. Personal watercraft speeds, wakes, and operations near other users can pose hazards and conflicts, especially to canoeists and sea kayakers. Kayakers and canoeists have complained about PWC, and other visitors have complained that PWC use conflicts with swimming and other beach activities. Under this proposed regulation, PWC would be reinstated in 10 special use areas throughout the national seashore. All visitors would experience beneficial impacts due to restricting PWC to flat-wake speeds when operating within national seashore boundaries, which should reduce conflicts between PWC and other users, particularly swimmers, anglers, and nonmotorized boaters. In addition, park staff would support the state boater education program; if such support resulted in more PWC operators enrolling in the program, all visitors could experience beneficial impacts as 83% of all PWC operators involved in accidents in North Carolina in 2003 had no formal PWC education. *PWC Users/Swimmer Conflicts* . Personal watercraft would have access to two special use areas on the soundside of Shackleford Banks, with a non-use area in between where the maritime forest fronts the shoreline. This non-use area was chosen based on congestion and safety issues at the island, where swimming and beach activities (including overnight camping) are common. Therefore, by restricting PWC use in this popular area, impacts on swimmers would be reduced compared to reinstating PWC throughout the entire island, and impacts would be negligible to minor and of short duration in this area. *PWC Users/Other Boater Conflicts* . Other motorized watercraft frequent the same areas, including the soundside of Shackleford Banks and the areas near the Cape Lookout lighthouse. Under this proposed regulation, PWC would have access to the same areas that are popular with boaters. The lighthouse area has been popular with PWC users in the past and continues to be a strong attraction for all national seashore visitors. Personal watercraft would be permitted to operate in three use areas in the Cape Lookout Bight area, being most restricted in the boat docking areas and beach near the lighthouse and the marshes near Catfish Point. A landing zone 300 feet north of the NPS ferry dock should help distribute PWC users accessing this area. Such restrictions, along with flat-wake speed requirements, should help alleviate potential conflicts with other boaters in this popular area and keep adverse impacts at minor levels. Personal watercraft would not be permitted to use marshlands along the North and South Core Banks, where kayakers have complained about PWC use in marshes from Cape Lookout north to New Drum Inlet. Conflicts and potential for accidents would be minimal farther north, where PWC use has historically been extremely low. *PWC Users/Other Visitor Conflicts.* Personal watercraft users would continue to conflict with other national seashore users, such as anglers and other beach recreationists. However, anglers fishing near the maritime forest on Shackleford Banks would benefit from PWC prohibition in this area. No accidents or injuries between PWC and non-PWC users have been reported to national seashore staff, although some could have occurred, particularly outside of the park's jurisdiction, and not been reported. Overall, reinstating PWC use in restricted areas would result in adverse, short- and long-term impacts that would vary from negligible in low-use areas, to minor in localized, high-use areas where a small number of visitors would be affected due the low numbers of PWC accessing the national seashore in restricted use areas, as well as the flat-wake speed restrictions called for under this proposed regulation. Cumulative impacts would be similar to those described under alternative A in the EA, although PWC use would be restricted to specific areas of the national seashore. When combined with increased visitation expected throughout the national seashore, particularly at the Cape Lookout lighthouse area, reinstating PWC would increase potential for conflicts and accidents, particularly in localized areas. However, the restrictions on Shackleford and the Cape Lookout area would help alleviate such problems. Therefore, cumulative impacts would be adverse, long-term and vary from negligible to moderate depending on location. Reinstating PWC use in restricted areas would result in adverse, short- and long-term impacts that would vary from negligible in low-use areas, to minor in localized, high-use areas where a small number of visitors would be affected due the low numbers of PWC accessing the national seashore in restricted use areas. Cumulative impacts would be adverse, long-term and vary from negligible to moderate depending on location. Cultural Resources The environment at Cape Lookout National Seashore has deterred extensive human settlement in the area. Human occupation of the Outer Banks region initially occurred over 3,000 years ago by a hunting-fishing-gathering people. The peoples of the Outer Banks are considered to be small groups of extended families, such as the situation among the living Algonkian hunters of the North. Earlier peoples may have used the area, but there is a strong likelihood that wave action or other natural processes removed any very early sites long ago. Little is known about the nomadic hunters on the islands, and specific information about the area up to the time of Colonial English occupation is lacking. Shell midden sites on the Shackleford Banks and at Cape Lookout are the only remains of early human occupation. However, these sites (most of which are outside the national seashore's jurisdiction) have been reduced to almost unintelligible remains. Cape Lookout National Recreation Area has 36 recorded archeological sites. These sites are difficult to monitor and protect due to the changing landscape of the barrier islands. Shell middens were found on the islands in the past, but most have been washed away by storms. None of the aboriginal sites currently known to exist within the national seashore were felt to be culturally and scientifically significant enough to justify their nomination to the National Historic Register. Of the 36 recorded archeological sites, some could potentially be impacted by PWC use at Cape Lookout. The majority of the sites exist on Shackleford Banks, primarily in the salt marshes; some are located on small, marshy islands adjacent to Shackleford. Little evidence of these sites remains due to advanced stages of erosion and other environmental factors. The sites have become damaged from overwash or are submerged at high tide, and only erosional remnants remain. Severe erosion and movement of the land mass have almost obliterated several sites. Some of the sites are covered with thick vegetation, obscuring portions of the site from view. One site has been affected by past use of the area by sheep and goats, to the extent that little evidence of the site remains intact. According to park staff, looting and vandalism of cultural resources is not a substantial problem. Under this proposed regulation, PWC users would have access to specific locations within the national seashore. When riding within NPS jurisdiction, PWC would be required to operate perpendicular to the shore and at flat-wake speed. Therefore, impacts on archeological sites from wave action would be greatly minimized. In addition, very few PWC have historically used the national seashore, and most would not operate in salt marsh areas where many archeological sites are located, further reducing the potential for adverse impact. Therefore, no negligible long-term, adverse impacts from PWC wave action would be expected. Potential impacts resulting from vandalism and illegal collection would be similar to those expected under alternative A. However, the PWC landing restrictions on Shackleford and Cape Lookout would prevent PWC from landing in areas with archeological sites. Although PWC users could land in the designated areas and walk to some sites, many are submerged or located in salt marshes on small satellite islands, which are difficult to access by foot or PWC. Other sites are obscured by thick vegetation and difficult to identify. Therefore, impacts from vandalism and looting (which have historically been insubstantial) are expected to be adverse, long-term, but negligible. Impacts from other boaters and visitors would be combined with impacts from PWC users. However, impacts from vandalism and illegal collecting would be negligible due to the difficulty in identifying these sites, as described above. Adverse effects due to wave action from boats would continue to impact aboriginal sites, but would not be appreciably augmented by waves from PWC use due to the flat-wake speed and perpendicular approach restrictions described under this proposed regulation. Wild horses would continue to impact archeological sites as described under alternative A. Past use of the area by sheep and goats could have also adversely impacted these sites. Erosion due to natural causes would continue to result in the most damaging impacts on archeological sites. Therefore, cumulative impacts resulting from vandalism, illegal collecting, waves from boats, and wild horses would be adverse, long-term, and negligible. Restricting areas of use and requiring PWC to operate perpendicular to the shore and at flat-wake speed within the national seashore's jurisdiction would minimize impacts on archaeological resources from wave action. Restricting areas of use would also minimize impacts resulting from vandalism and illegal collecting. Cumulative impacts would be adverse, long-term, and negligible. Therefore, implementation of this proposed regulation would not result in an impairment of cultural resources. The Proposed Rule Under this NPRM, which is based on the preferred alternative, alternative B, a special regulation at 36 CFR 7.49 would reinstate PWC use at the national seashore. Under the proposed rule, special use areas would be identified where PWC could access certain sections of Shackleford Banks, South Core Banks, and North Core Banks. Personal watercraft would be prohibited in all other areas of the national seashore, and PWC would not be allowed to beach on the oceanside. Safety and operating restrictions would be dictated by the North Carolina PWC regulations outlined under alternative A and additional NPS operating restrictions. The state of North Carolina ceded legal jurisdiction to the NPS for all land and waters from the mean low water on the oceanside to 150 feet from the mean low water mark on the soundside. Waters beyond this 150 feet boundary within Back Sound and beyond the legislated boundary along Core Sound are managed by the state of North Carolina. National Park Service legal jurisdiction on the oceanside of Shackleford Banks, South Core Banks, and North Core Banks is to the mean low water mark. *Special Use Areas.* Ten special use areas would provide for PWC access within Cape Lookout National Seashore boundaries. Personal watercraft would be allowed to access these areas on North Core Banks, South Core Banks (including Cape Lookout), and Shackleford Banks by remaining perpendicular to shore and operating at flat-wake speed. Under the proposed rule, PWC use would not be authorized for recreational use parallel to the shoreline, but only for access to those areas identified below specifically for landing purposes. In all cases, PWC would have access to the sound side of the barrier islands only. No PWC access to the seashore's ocean side would be permitted. The ten special use areas identified in the proposed rule include the following: 1. North Core Banks • Ocracoke Inlet Access—Wallace Channel dock to the demarcation line in Ocracoke Inlet, near Milepost 1. • Milepost 11B Access—Existing sound-side dock at Mile post 11B approximately 4 miles north of Long Point. • Long Point Access—Ferry landing at Long Point cabin area (formerly called the Morris Marina Kabin Kamp) near Milepost 16. • Old Drum Inlet Access—Soundside beach near Milepost 19 (as designated by signs), approximately 1/2 mile north of Old Drum inlet (adjacent to the cross-over route) encompassing approximately 50 feet. 2. South Core Banks • New Drum Inlet Access—Sound-side beach near Milepost 23 (as designated by signs), approximately 1/4 mile long, beginning approximately 1/2 mile south of New Drum Inlet. • Great Island Access—Carly Dock at the Great Island cabin area (formerly called the Alger Willis Fish Camp) near Milepost 30 (noted as South Core Banks-Great Island on map). 3. Cape Lookout • Lighthouse Area North Access—A zone 300 feet north of the NPS dock at the lighthouse ferry dock near Milepost 41. • Lighthouse Area South Access—Sound-side beach 100 feet south of the “summer kitchen” to 200 feet north of the Cape Lookout Environmental Education Center Dock. • Power Squadron Spit Access—Sound-side beach at Power Squadron Spit across from rock jetty to end of the spit. 4. Shackleford Banks • Shackleford West End Access—Soundside beach at Shackleford Banks from Whale Creek west to Beaufort Inlet, except the area between the Wade Shores toilet facility and the passenger ferry dock. *Access and Wake Restrictions.* Within these special use areas, all PWC would be required to remain perpendicular to shore and operate at flat-wake speed that would result in no visible wake within park waters. *Equipment and Emissions.* As noted in the EA, the Environmental Protection Agency promulgated a rule to control exhaust emissions from new marine engines, including outboards and PWC. Emission controls provide for increasingly stricter standards beginning in model year 1999 (EPA 1996a, 1997). Under this alternative, it is assumed that PWC two-stoke engines would be converted to cleaner direct-injected or four-stroke engines in accordance with the Environmental Protection Agency's assumptions (40 CFR parts 89-91, “Air Pollution Control; Gasoline Spark-Ignition and Spark-Ignition Engines, Exemptions; Rule, 1996). This proposed rule would not accelerate this conversion from two-stroke to four-stroke engines for PWC. *Visitor Education.* Cape Lookout park staff would support the state boater education program by annually outlining state and park PWC regulations within park brochures such as the park newspaper. Park staff would educate visitors about PWC regulations in park and state waters to help them understand the differences between park regulations and PWC regulations for other local jurisdictions along the Outer Banks. *Cooperation with Local Entities.* The park would work with local and state governments to encourage consistent PWC user behavior within state waters adjacent to park PWC special use areas. The park would like to encourage the state to define a PWC use zone in state waters adjacent to Cape Lookout National Seashore that would encourage flat-wake and perpendicular access to the shore. Compliance With Other Laws Regulatory Planning and Review (Executive Order 12866) This document is not a significant rule and has not been reviewed by the Office of Management and Budget under Executive Order 12866.
(1)This rule will not have an effect of $100 million or more on the economy. It will not adversely affect in a material way the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities. The NPS has completed the report “Economic Analysis of Personal Watercraft Regulations in Cape Lookout National Seashore” (MACTEC Engineering, December 2005). This document may be viewed on the park's Web site at: *http://www.nps.gov/calo/pphtml/documents.html.*
(2)This rule will not create a serious inconsistency or otherwise interfere with an action taken or planned by another agency. Actions taken under this rule will not interfere with other agencies or local government plans, policies or controls. This rule is an agency specific rule.
(3)This rule does not alter the budgetary effects of entitlements, grants, user fees, or loan programs or the rights or obligations of their recipients. This rule will have no effects on entitlements, grants, user fees, or loan programs or the rights or obligations of their recipients. No grants or other forms of monetary supplements are involved.
(4)This rule does not raise novel legal or policy issues. This rule is one of the special regulations being issued for managing PWC use in National Park Units. The NPS published general regulations (36 CFR 3.24) in March 2000, requiring individual park areas to adopt special regulations to authorize PWC use. The implementation of the requirement of the general regulation continues to generate interest and discussion from the public concerning the overall effect of authorizing PWC use and NPS policy and park management. Regulatory Flexibility Act The Department of the Interior certifies that this rulemaking will not have a significant economic effect on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 *et seq.* ). This certification is based on a report entitled “Economic Analysis of Personal Watercraft Regulations in Cape Lookout National Seashore” (MACTEC Engineering, December 2005). This document may be viewed on the park's Web site at: *http://www.nps.gov/calo/pphtml/documents.html.* Small Business Regulatory Enforcement Fairness Act (SBREFA) This rule is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. This proposed rule: a. Does not have an annual effect on the economy of $100 million or more. b. Will not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions. c. Does not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises. Unfunded Mandates Reform Act This rule does not impose an unfunded mandate on State, local, or tribal governments or the private sector of more than $100 million per year. The rule does not have a significant or unique effect on State, local or tribal governments or the private sector. This rule is an agency specific rule and does not impose any other requirements on other agencies, governments, or the private sector. Takings (Executive Order 12630) In accordance with Executive Order 12630, the rule does not have significant takings implications. A taking implication assessment is not required. No taking of personal property will occur as a result of this rule. Federalism (Executive Order 13132) In accordance with Executive Order 13132, the rule does not have sufficient federalism implications to warrant the preparation of a Federalism Assessment. This proposed rule only affects use of NPS administered lands and waters. It has no outside effects on other areas by allowing PWC use in specific areas of the park. Civil Justice Reform (Executive Order 12988) In accordance with Executive Order 12988, the Office of the Solicitor has determined that this rule does not unduly burden the judicial system and meets the requirements of sections 3(a) and 3(b)(2) of the Order. Paperwork Reduction Act This regulation does not require an information collection from 10 or more parties and a submission under the Paperwork Reduction Act is not required. An OMB Form 83-I is not required. National Environmental Policy Act The NPS has analyzed this rule in accordance with the criteria of the National Environmental Policy Act and has prepared an EA. The EA was available for public review and comment from January 24, 2005, to February 24, 2005. Copies of the EA may be downloaded at *http://www.nps.gov/calo/pphtml/documents.html* or requested by telephoning
(252)728-2250. Mail inquiries should be directed to park headquarters: Cape Lookout National Seashore, 131 Charles Street, Harkers Island, NC 28531. Government-to-Government Relationship With Tribes In accordance with the President's memorandum of April 29, 1994, “Government to Government Relations with Native American Tribal Governments” (59 FR 22951) and 512 DM 2, we have evaluated potential effects on federally recognized Indian tribes and have determined that there are no potential effects. Clarity of Rule Executive Order 12866 requires each agency to write regulations that are easy to understand. We invite your comments on how to make this rule easier to understand, including answers to questions such as the following:
(1)Are the requirements in the rule clearly stated?
(2)Does the rule contain technical language or jargon that interferes with its clarity?
(3)Does the format of the rule (grouping and order of sections, use of headings, paragraphing, etc.) aid or reduce its clarity?
(4)Would the rule be easier to read if it were divided into more (but shorter) sections? (A “section” appears in bold type and is preceded by the symbol “§ ” and a numbered heading; for example § 7.49, Cape Lookout National Seashore.)
(5)Is the description of the rule in the Supplementary Information section of the preamble helpful in understanding the proposed rule? What else could we do to make the rule easier to understand? Send a copy of any comments that concern how we could make this rule easier to understand to: Office of Regulatory Affairs, Department of the Interior, Room 7229, 1849 C Street, NW., Washington, DC 20240. You may also e-mail the comments to this address: *Exsec@ios.doi.gov.* *Drafting Information:* The primary authors of this regulation are: Robert A. Vogel, Superintendent, Wouter Ketel, Chief Ranger, Michael W. Rikard, Chief of Resource Management, Jeff R. Cordes, Resource Management Specialist, Michael E. McGee, Facility Manager, Donna Tipton, Administrative Officer, Cape Lookout National Seashore; Sarah Bransom, Environmental Quality Division; and Jerry Case, NPS, Washington, DC. Public Participation If you wish to comment, you may mail or hand deliver your comments to: Cape Lookout National Seashore, 131 Charles Street, Harkers Island, NC 28531. Comments may also be submitted on the Federal rulemaking portal: *http://www.regulations.gov* Follow the instructions for submitting comments. Please identify comments by: RIN 1024-AD44. Our practice is to make comments, including names and addresses of respondents, available for public review during regular business hours. Individual respondents may request that we withhold their home address from the rulemaking record, which we will honor to the extent allowable by law. If you wish us to withhold your name and/or address, you must state this prominently at the beginning of your comment. However, we will not consider anonymous comments. We will make all submissions from organizations or businesses, and from individuals identifying themselves as representatives or officials or organizations or businesses, available for public inspection in their entirety. List of Subjects in 36 CFR Part 7 District of Columbia, National Parks, Reporting and recordkeeping requirements. In consideration of the foregoing, the NPS proposes to amend 36 CFR part 7 as follows: PART 7—SPECIAL REGULATIONS, AREAS OF THE NATIONAL PARK SYSTEM 1. The authority for part 7 continues to read as follows: Authority: 16 U.S.C. 1, 3, 9a, 460(q), 462(k); sec. 7.96 also issued under D.C. Code 8-137
(1981)and D.C. Code 40-721 (1981). 2. Add new § 7.49 to read as follows: § 7.49 Cape Lookout National Seashore. Personal watercraft
(PWC)may operate within Cape Lookout National Seashore only under the conditions specified in paragraphs
(a)through
(e)of this section and in the designated areas specified paragraph
(f)in this section.
(a)PWC are allowed in the following areas only when remaining perpendicular to shore and operating at flat-wake speed.
(b)PWC use is not authorized for recreational use parallel to the shoreline, but only for access to the following areas specifically for landing purposes.
(c)In all cases, PWC have access to the sound side of the barrier islands only.
(d)PWC are prohibited in all areas of the national seashore except for the areas listed in paragraph
(f)of this section. PWC are not allowed to beach on the oceanside.
(e)The Superintendent may temporarily limit, restrict or terminate access to the areas designated for PWC use after taking into consideration public health and safety, natural and cultural resource protection, and other management activities and objectives.
(f)PWC use is allowed only in the locations specified in this paragraph.
(1)North Core Banks: Access Location
(i)Ocracoke Inlet Wallace Channel dock to the demarcation line in Ocracoke Inlet near Milepost 1.
(ii)Milepost 11B Existing sound-side dock at mile post 11B approximately 4 miles north of Long Point.
(iii)Long Point Ferry landing at the Long Point Cabin area.
(iv)Old Drum Inlet Sound-side beach near Milepost 19 (as designated by signs), approximately 1/2 mile north of Old Drum inlet (adjacent to the cross-over route) encompassing approximately 50 feet.
(2)South Core Banks: Access Location
(i)New Drum Inlet Sound-side beach near Milepost 23 (as designated by signs), approximately 1/4 mile long, beginning approximately 1/2 mile south of New Drum Inlet.
(ii)Great Island Access. Carly Dock at Great Island Camp, near Milepost 30 (noted as South Core Banks-Great Island on map).
(3)Cape Lookout Access Location
(i)Lighthouse Area North A zone 300 feet north of the NPS dock at the lighthouse ferry dock near Milepost 41.
(ii)Lighthouse Area South Sound-side beach 100 feet south of the “summer kitchen” to 200 feet north of the Cape Lookout Environmental Education Center Dock.
(iii)Power Squadron Spit Sound-side beach at Power Squadron Spit across from rock jetty to end of the spit
(4)Shackleford Banks West End Access Sound-side beach at Shackleford Banks from Whale Creek west to Beaufort Inlet, except the area between the Wade Shores toilet facility and the passenger ferry dock. Dated: December 20, 2005. Paul Hoffman, Acting Assistant Secretary, Fish and Wildlife and Parks. [FR Doc. E5-8003 Filed 12-28-05; 8:45 am] BILLING CODE 4312-52-P ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 51 and 96 [EPA-HQ-OAR 2003-0053; FRL-8016-6] Rule To Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule): Supplemental Notice of Reconsideration AGENCY: Environmental Protection Agency (EPA). ACTION: Notice of reconsideration; request for comment; notice of opportunity for public hearing. SUMMARY: On May 12, 2005, EPA published in the **Federal Register** the final “Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone” (Clean Air Interstate Rule or CAIR). The CAIR requires certain upwind States to reduce emissions of nitrogen oxides (NO <sup>X</sup> ) and/or sulfur dioxide (SO <sup>2</sup> ) that significantly contribute to nonattainment of, or interfere with maintenance by, downwind States with respect to the fine particle (PM <sup>2.5</sup> ) and/or 8-hour ozone national ambient air quality standards (NAAQS). Subsequently, EPA received 11 petitions for reconsideration of the final rule. Through **Federal Register** notices dated August 24, 2005 and December 2, 2005, EPA previously initiated reconsideration processes on five specific issues in the CAIR and requested comment on those issues. In this notice, EPA is announcing its decision to reconsider one additional specific issue in the CAIR and is requesting comment on that issue. The specific issue addressed in today's notice relates to the potential impact of a recent D.C. Circuit Court decision, *New York* v. *EPA* , 413 F.3d 3 (D.C. Cir. 2005), on the analysis used in developing CAIR to identify highly cost-effective emission reductions. This court decision vacated the pollution control project
(PCP)exclusion in the New Source Review
(NSR)regulations (the exclusion allowed certain environmentally beneficial PCPs to be excluded from certain NSR requirements). The EPA is seeking comment only on the aspect of the CAIR specifically identified in this notice. We will not respond to comments addressing other provisions of the CAIR or any related rulemakings. DATES: Comments must be received on or before February 16, 2006. If requested, a public hearing will be held on January 17, 2006 in Washington, DC. For additional information on a public hearing, see the SUPPLEMENTARY INFORMATION section of this preamble. ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2003-0053, by one of the following methods: • *www.regulations.gov* : Follow the on-line instructions for submitting comments. Attention Docket ID No. EPA-HQ-OAR-2003-0053. • *E-mail:* *A-and-R-Docket@epa.gov* . Attention Docket ID No. EPA-HQ-OAR-2003-0053. • *Fax:* The fax number of the Air Docket is
(202)566-1741. Attention Docket ID No. EPA-HQ-OAR-2003-0053. • *Mail:* EPA Docket Center, EPA West (Air Docket), Attention Docket ID No. EPA-HQ-OAR-2003-0053, Environmental Protection Agency, Mailcode: 6102T, 1200 Pennsylvania Ave., NW., Washington, DC 20460. • *Hand Delivery:* EPA Docket Center (Air Docket), Attention Docket ID No. EPA-HQ-OAR-2003-0053, Environmental Protection Agency, 1301 Constitution Avenue, NW., Room B102; Washington, 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-OAR-2003-0053. 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 www.regulations.gov or e-mail. The *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 *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 information about EPA's public docket visit the EPA Docket Center homepage at *http://www.epa.gov/epahome/dockets.htm.* For additional instructions on submitting comments, go to the SUPPLEMENTARY INFORMATION section of this document. *Docket:* All documents in the docket are listed in the *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 EPA Docket Center (Air Docket), EPA/DC, EPA West, Room B102, 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. FOR FURTHER INFORMATION CONTACT: For general questions concerning today's action as well as questions concerning the analyses described in section III of this notice, please contact Meg Victor, U.S. EPA, Office of Atmospheric Programs, Clean Air Markets Division, Mail Code 6204J, 1200 Pennsylvania Avenue, NW., Washington, DC 20460, telephone
(202)343-9193, e-mail address *victor.meg@epa.gov.* For legal questions, please contact Sonja Rodman, U.S. EPA, Office of General Counsel, Mail Code 2344A, 1200 Pennsylvania Avenue, NW., Washington, DC 20460, telephone 202-564-4079, e-mail address *rodman.sonja@epa.gov* . For information concerning a public hearing, please contact Jo Ann Allman, U.S. EPA, Office of Air Quality Planning and Standards, Air Quality Strategies and Standards Division, Mail Code C539-02, Research Triangle Park, NC 27711, phone number
(919)541-1815, e-mail address *allman.joann@epa.gov.* SUPPLEMENTARY INFORMATION: General Information A. Does This Action Apply to Me? The CAIR does not directly regulate emissions sources. Instead, it requires States to develop, adopt, and submit State implementation plan
(SIP)revisions that would achieve the necessary SO <sup>2</sup> and NO <sup>X</sup> emissions reductions, and leaves to the States the task of determining how to obtain those reductions, including which entities to regulate. B. What Should I Consider as I Prepare My Comments for EPA? Note that general instructions for submitting comments are provided above under the ADDRESSES section. *1. Submitting CBI.* Do not submit this information to EPA through *http://www.regulations.gov* or e-mail. Clearly mark the part or all of the information that you claim to be CBI. For CBI information in a disk or CD ROM that you mail to EPA, mark the outside of the disk or CD ROM as CBI and then identify electronically within the disk or CD ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. Send or deliver information identified as CBI only to the following address: Roberto Morales, U.S. EPA, Office of Air Quality Planning and Standards, Mail Code C404-02, Research Triangle Park, NC 27711, telephone
(919)541-0880, e-mail at *morales.roberto@epa.gov* , Docket ID No. EPA-HQ-OAR-2003-0053. *2. Tips for Preparing Your Comments* . When submitting comments, remember to: • Identify the rulemaking by docket number and other identifying information (subject heading, **Federal Register** date and page number). • Follow directions—The agency may ask you to respond to specific questions or organize comments by referencing a Code of Federal Regulations
(CFR)part or section number. • Explain why you agree or disagree; suggest alternatives and substitute language for your requested changes. • Describe any assumptions and provide any technical information and/or data that you used. • If you estimate potential costs or burdens, explain how you arrived at your estimate in sufficient detail to allow for it to be reproduced. • Provide specific examples to illustrate your concerns, and suggest alternatives. • Explain your views as clearly as possible, avoiding the use of profanity or personal threats. • Make sure to submit your comments by the comment period deadline identified. Public Hearing If requested, EPA will hold a public hearing on today's notice. The EPA will hold a hearing only if a party notifies EPA by January 10, 2006, expressing its interest in presenting oral testimony on issues addressed in today's notice. Any person may request a hearing by calling Jo Ann Allman at
(919)541-1815 before 5 p.m. on January 10, 2006. Any person who plans to attend the hearing should visit the EPA's Web site at *http://www.epa.gov/cair* or contact Jo Ann Allman at
(919)541-1815 to learn if a hearing will be held. If a public hearing is held on today's notice, it will be held on January 17, 2006 at EPA Headquarters, 1310 L Street (closest cross street is 13th Street), 1st floor conference rooms 152 and 154, Washington, DC. The closest Metro stop is McPherson Square (Orange and Blue lines)—take 14th Street/Franklin Square Exit. Because the hearing will be held at a U.S. Government facility, everyone planning to attend should be prepared to show valid picture identification to the security staff in order to gain access to the meeting room. If held, the public hearing will begin at 10 a.m. and end at 2 p.m. The hearing will be limited to the subject matter of this document. Oral testimony will be limited to 5 minutes. The EPA encourages commenters to provide written versions of their oral testimonies either electronically (on computer disk or CD ROM) or in paper copy. The public hearing schedule, including the list of speakers, will be posted on EPA's Web site at *http://www.epa.gov/cair* . Verbatim transcripts and written statements will be included in the rulemaking docket. A public hearing would provide interested parties the opportunity to present data, views, or arguments concerning issues addressed in today's notice. The EPA may ask clarifying questions during the oral presentations, but would not respond to the presentations or comments at that time. Written statements and supporting information submitted during the comment period will be considered with the same weight as any oral comments and supporting information presented at a public hearing. All written comments must be received by EPA on or before February 16, 2006. Because of the need to resolve the issues in this document in a timely manner, EPA will not grant requests for extensions of the public comment period. Availability of Related Information Documents related to the CAIR are available for inspection in Docket No. EPA-HQ-OAR-2003-0053 at the address and times given above. The EPA has established a Web site for the CAIR at *http://www.epa.gov/cleanairinterstaterule* or more simply *http://www.epa.gov/cair/.* Outline I. Background II. Today's Action A. Grant of Reconsideration B. Schedule for Reconsideration III. Impact on CAIR Analyses of DC Circuit Decision in New York v. EPA A. Background on *New York* v. *EPA* and its Relationship to CAIR B. Potential Impact of Collateral Pollutant Increases and Mitigation Measures 1. Increases in Sulfuric Acid Emissions From SCR Retrofits 2. Increases in Sulfuric Acid Emissions From Wet FGD Retrofits in Combination With Switching to Higher Sulfur Coal 3. Summary of Combinations of CAIR SCR and/or FGD Retrofits and Coal Switches That May Increase Sulfuric Acid Emissions 4. Technology Options Available for Mitigating Sulfuric Acid Emission Increases 5. Analysis of SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> Mitigation Costs and Timing Impacts for CAIR SCR and/or Wet FGD Projects 6. Increases in Carbon Monoxide and Unburned Carbon (Solid Particulate) Emissions From Combustion Controls 7. Increases in Direct PM <sup>2.5</sup> Resulting From Fugitive Emissions From Storage or Handling of Lime, Limestone, or FGD Waste After Installation of Dry or Wet FGD 8. Collateral Air Pollutant Emissions From Units Switching From High to Low Sulfur Coals 9. Summary of Section III.B. C. Potential Impact of NSR Permitting IV. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review B. Paperwork Reduction Act C. Regulatory Flexibility Act 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 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 I. Background On May 12, 2005, the EPA (Agency or we) promulgated the final “Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone” (Clean Air Interstate Rule or CAIR)(70 FR 25162). As explained in the CAIR preamble and summarized in our December 2, 2005 reconsideration notice (70 FR 72268), CAIR requires 28 States and the District of Columbia to revise their State implementation plans
(SIPs)to include control measures to reduce emissions of SO <sup>2</sup> and/or NO <sup>X</sup> . Sulfur dioxide is a precursor to PM <sup>2.5</sup> formation and NO <sup>X</sup> is a precursor to PM <sup>2.5</sup> and ozone formation. By reducing upwind emissions of SO <sup>2</sup> and NO <sup>X</sup> , CAIR will assist downwind PM <sup>2.5</sup> and 8-hour ozone nonattainment areas in achieving the NAAQS. As also described in the December 2005 reconsideration notice, the CAIR was promulgated through a process that involved significant public participation (70 FR 72271). Following publication of the final CAIR on May 12, 2005, the Administrator received eleven petitions requesting reconsideration of certain aspects of the final rule. The complete petitions are available in the docket for the CAIR. 1 The petitions were filed pursuant to section 307(d)(7)(B) of the CAA. Under this provision, the Administrator is to initiate reconsideration proceedings if the petitioner can show that an objection is of central relevance to the rule and that it was impracticable to raise the objection to the rule within the public comment period or that the grounds for the objection arose after the public comment period but before the time for judicial review had run. 1 Petitions for reconsideration were filed by: State of North Carolina (OAR-2003-0053-2192); FPL Group (OAR-2003-0053-2201); Florida Association of Electric Utilities (OAR-2003-0053-2200); Entergy Corporation (OAR-2003-0053-2195 and 2198 (attachment 1)); Massachusetts Department of Environmental Protection (OAR-2003-0053-2199); Integrated Waste Services Association (OAR-2003-0053-2193); Texas Commission on Environmental Quality (OAR-2003-0053-2212); Northern Indiana Public Service Corporation (OAR-2003-0053-2194 and 2213 (supplemental petition)); City of Amarillo, Texas, El Paso Electric Company, Occidental Permian Ltd, and Southwestern Public Service Company d/b/a/ Xcel Energy (OAR-2003-0053-2196 and 2197 (attachment 1) and 2205-2207 (attachments 2-4)); Connecticut Business and Industry Ass'n (OAR-2003-0053-2203); and Minnesota Power, a division of ALLETE. Inc. (OAR-2003-0053-2212). The EPA has already initiated a reconsideration process on five specific aspects of the final CAIR. On August 24, 2005 (70 FR 49708) and on December 2, 2005 (70 FR 72268), we published in the **Federal Register** notices announcing these decisions to reconsider specific aspects of the CAIR and requesting comment on those issues. Today's notice announces EPA's decision to reconsider one additional issue raised in a petition for reconsideration and requests comment on that additional issue. By a letter dated December 22, 2005 we informed a petitioner of our intent to grant reconsideration on an issue addressed in their petition for reconsideration. We indicated in that letter that we would initiate the reconsideration process by publishing this notice. II. Today's Action A. Grant of Reconsideration In this notice, EPA is announcing its decision to grant reconsideration on one issue raised in the petitions for reconsideration. This notice initiates that reconsideration process and requests comment on the issue to be addressed. Given the intense public interest in this rule, EPA has decided to provide this additional opportunity for public comment. At this time, however, EPA does not believe that any of the information submitted to date demonstrates that EPA's final decisions were erroneous or inappropriate. Therefore, we are not proposing any modifications to the final CAIR. The issue on which EPA is requesting comment relates to the potential impact of a recent judicial opinion on the highly cost-effective analysis prepared by EPA in developing the CAIR. This case, *New York* v. *EPA* , 413 F.3d 3 (D.C. Cir. 2005) was decided on June 24, 2005—after the final CAIR was published but before the time for judicial review of the rule had run. This issue is described in greater detail in Section III of this notice. The EPA is requesting comment only on the issue specifically described in Section III. We are not taking comment on any other provisions in the CAIR or otherwise reopening any other issues decided in the CAIR for reconsideration or comment. B. Schedule for Reconsideration For the issue addressed in this notice, EPA expects to take final action on reconsideration by March 15, 2006. By that date, EPA will finalize the process of reconsideration by issuing a final rule or proposing a new approach. EPA also expects, by March 15, 2006, to issue decisions on all remaining issues raised in the petitions for reconsideration. III. Impact on CAIR Analyses of DC Circuit Decision in New York v. EPA A. Background on New York v. EPA and Its Relationship to CAIR One industry petitioner claims that a recent opinion of the DC Circuit raises questions about the sufficiency of EPA's analysis prepared for the CAIR to identify highly cost-effective emission reductions. The petitioner argues that EPA should reconsider this analysis to take into account the potential impact of the decision in *New York* v. *EPA* , 413 F.3d 3 (D.C. Cir. 2005). This judicial opinion was issued on June 24, 2005—after the final CAIR had been promulgated, but within the 60 days provided by CAA section 307(b) for filing of petitions for review. 2 Among other things, the opinion vacated a provision of the New Source Review
(NSR)regulations, commonly known as the pollution control project
(PCP)exclusion. All pending petitions for rehearing of the case were denied by the Court on December 9, 2005. The EPA's request that the Court clarify its holding with regard to any retroactive effect of its ruling on the PCP issue was also denied. The Court determined that this clarification request was premature because no specific retroactive application of the provision was before the Court. The time for filing Petitions for Certiorari with the United States Supreme Court has not yet run. The analysis that follows looks at the potential impact of the *New York* v. *EPA* decision. 2 CAA section 307(d)(7)(B) provides that the Administrator shall convene a proceeding for reconsideration if the person raising an objection can show that: it was impracticable to raise the objection during the period for public comment or the grounds for the objection arose after such period but within the time specified for judicial review; and the objection is of central relevance to the outcome of the rule. The PCP exclusion provided a mechanism for sources to exclude certain environmentally beneficial PCPs from the definition of “major modification” under Prevention of Significant Deterioration (PSD)/NSR 3 even though the PCP resulted in a significant net emissions increase in a collateral pollutant ( *e.g.* , increase in NO <sup>X</sup> from flaring VOCs). This exclusion could only apply if the owner or operator, before beginning construction of the PCP, either provided notice to the Administrator (for certain projects listed in the regulations) or submitted a permit application to obtain approval to use the exclusion. If the exclusion were found not to apply, the source would either have to ensure that the PCP did not result in a significant net emissions increase in a collateral NSR-regulated pollutant (and thus avoid NSR review), or apply for and receive a NSR permit for the project. Petitioner asks EPA to reconsider whether EPA's highly cost effective analysis “continues to be valid given the court's holding in [ *New York* v. *EPA* ].” More specifically, Petitioner claims that CAIR sources will need to go through NSR permitting and that additional time and financial costs will be required for this permitting. Petitioner does not specify which projects it believes might require NSR permitting or what collateral increases in NSR-regulated pollutants it expects. Petitioner also claims that additional time will be necessary for NSR permitting and that therefore the compliance deadlines of January 1, 2009 and 2010 are “in jeopardy.” Petitioner, however, does not ask EPA to reconsider the 2009 and 2010 compliance deadlines. As noted above, this notice grants reconsideration only on the issue of the impact of the *New York* v. *EPA* decision on EPA's highly cost effective analysis. 3 PSD is the part of the NSR program that applies to sources located in areas in attainment with the NAAQS. Unless otherwise noted, in this notice, when we refer to the NSR program, NSR review, NSR permitting or other NSR requirements, we are referring to both the NSR and PSD programs and their respective requirements. In developing the CAIR, EPA conducted extensive analyses to identify highly cost-effective SO <sup>2</sup> and NO <sup>X</sup> emissions reductions based on controlling EGUs. These analyses are explained in the preamble to the CAIR (70 FR 25202-25212). The EPA has reviewed the petition for reconsideration and analyzed the potential impact of *New York* v. *EPA* on the CAIR cost-effectiveness determination and timing. This analysis indicates that some EGUs that install SO <sup>2</sup> and/or NO <sup>X</sup> controls for CAIR may incur relatively minor additional costs and minor impacts on timing as a result of *New York* v. *EPA* , but these potential impacts will neither affect the highly cost-effective determination that the Agency made in CAIR nor impact the timeframe for CAIR reductions. The EPA's analysis further shows that options exist that would allow units to meet the CAIR deadlines without changing plans to stagger PCP projects (sources will not be forced to install all PCPs at one time) and that the related costs would not alter the highly cost effective analysis done for the final CAIR. The EPA invites comments on this analysis and the potential impact of the *New York* v. *EPA* decision on EPA's highly cost-effective determination. EPA's analysis of this issue is summarized below and supplemental information is in the CAIR docket. In order to evaluate the petitioner's claim, the Agency examined the potential for collateral increases in NSR-regulated air pollutants from the types of NO <sup>X</sup> and SO <sup>2</sup> controls on which EPA based its CAIR cost-effectiveness determination. 4 The EPA identified which of these technologies could have the potential to cause collateral increases in NSR-regulated air pollutants. The EPA then analyzed whether sources could mitigate any such collateral increases to avoid NSR review and analyzed the cost and timing impacts associated with potential mitigation measures. The EPA determined that projected collateral increases in NSR-regulated pollutants that might be significant enough to trigger an NSR threshold could be mitigated by many sources wishing to avoid the NSR permitting process. However, some sources may not be able to ensure mitigation of all collateral increases. Therefore, the Agency also analyzed the impacts associated with NSR permitting for these NO <sup>X</sup> and SO <sup>2</sup> pollution control projects. 4 All references to “collateral increases” in this document refer to potential collateral increases in NSR-regulated air pollutants. The EPA considered each of the NO <sup>X</sup> and SO <sup>2</sup> control measures that were included in the CAIR cost-effectiveness determination and found that the following technologies may have the potential to cause collateral increases in air pollutants regulated under NSR: combustion controls, selective catalytic reduction (SCR), flue gas desulphurization (FGD), and fuel switches to low sulfur coal. Many affected sources can choose to implement measures to mitigate the potential collateral emission increases (thereby obviating the need to undertake NSR analysis). The Agency determined that some cost increases will result from actions that sources may take to mitigate collateral increases that result from CAIR control actions; however these impacts do not alter the final highly cost effective determination made in the final CAIR. In addition, implementing these control actions will not affect the feasibility of implementing the CAIR reductions in the required timeframe. Further, if some sources apply for an NSR permit, the Agency believes that the impacts of NSR permitting will not affect the CAIR highly cost-effectiveness determination or the CAIR timeline. Note that in today's notice the Agency is not making any determination or prediction regarding what the specific NSR requirements might be for such projects. The EPA's analysis for each of these NO <sup>X</sup> and SO <sup>2</sup> controls is discussed below and in a Technical Support Document
(TSD)available in the docket entitled “Technical Support Document: Impact on CAIR Analyses of D.C. Circuit Decision in *New York* v. *EPA* .” B. Potential Impact of Collateral Pollutant Increases and Mitigation Measures 1. Increases in Sulfuric Acid Emissions From SCR Retrofits 5 5 This SCR discussion is focused on the potential for sulfuric acid emission increases from SCR retrofits. Note that SCR conditions also favor a reaction between SO <sup>3</sup> and ammonia that produces ammonium bisulfate which condenses to form solid PM, however the majority of this PM will be captured in the particulate control device installed at the unit. Any such increase in PM emissions would likely not be significant enough to trigger NSR review, even when considered together with the small increase in PM emissions that could occur from storage or handling lime, limestone, or FGD waste (see discussion below). Many CAIR units are projected to install selective catalytic reduction
(SCR)to reduce NO <sup>X</sup> emissions. The SCR catalyst oxidizes a portion of the SO <sup>2</sup> present in flue gas to SO <sup>3</sup> . The amount of SO <sup>3</sup> added to the flue gas stream by SCR will be directly proportional to the fuel sulfur content. (Note that SO <sup>2</sup> is also oxidized to SO <sup>3</sup> in the boiler itself.) Some SO <sup>3</sup> reacts with moisture in the flue gas to form sulfuric acid (H <sup>2</sup> SO <sup>4</sup> ) and exits the stack as sulfuric acid vapor. The Agency's analysis for today's notice assumes that all sulfuric acid emitted will be counted as emissions of sulfuric acid mist—an NSR-regulated pollutant. Sulfuric acid mist is also regulated under NSR as PM <sup>2.5</sup> (a criteria pollutant). Because PM <sup>2.5</sup> is a criteria pollutant, the NSR requirements vary depending on the location of the unit experiencing the emission increase, i.e., whether the unit is located in a nonattainment area. See further discussion of the Agency's analysis regarding permitting for these projects, below. Although SCR retrofits can lead to increased sulfuric acid emissions, for the following reasons EPA expects that many units installing SCR for CAIR will not actually increase their sulfuric acid emissions and will therefore not incur any cost increase or timing burden associated with collateral increases of sulfuric acid: *Installing Both SCR and FGD* . Many CAIR units that are expected to install SCR to reduce NO <sup>X</sup> emissions also are expected to install flue gas desulphurization
(FGD)to reduce SO <sup>2</sup> emissions, and FGD is also effective at reducing SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> emissions. The two most common types of FGD systems (on which the Agency's CAIR cost-effectiveness analysis was based) are a lime-based spray dryer system (dry FGD) and a limestone-based wet FGD system (wet FGD). Considering the effectiveness of FGD at mitigating SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> emissions, the Agency expects that a CAIR unit installing SCR and FGD at the same time would not increase sulfuric acid emissions significantly enough to trigger NSR. Note that some units may switch to a higher sulfur coal when they install FGD. The combination of installing SCR and dry FGD and switching to high sulfur coal may not result in increased sulfuric acid because dry FGD is very effective at mitigating SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> . However, installation of SCR in combination with wet FGD and a switch to high sulfur coal could result in a significant net increase in sulfuric acid emissions. *Switching to Lower Sulfur Coal with SCR Retrofit* . Some CAIR units that burn high sulfur coal may also choose to switch to lower sulfur coal when installing SCR. For units switching from high to low sulfur coal and installing SCR, there would likely be no net increase in sulfuric acid emissions. *Ceasing to Inject SO* 3 *with SCR Retrofit* . Many CAIR units have cold-side electrostatic precipitators
(ESP)in place to control particulate matter emissions. These control devices perform better with SO <sup>3</sup> present in the flue gas. Some units that have previously switched from higher-to lower-sulfur coal use injected SO <sup>3</sup> to bring the cold-side ESP performance back up. If such a unit installs SCR for CAIR, then the increased SO <sup>3</sup> from the SCR would lessen or obviate the need for SO <sup>3</sup> injection, and without the SO <sup>3</sup> injection there may be no net increase in sulfuric acid emissions. 2. Increases in Sulfuric Acid Emissions From Wet FGD Retrofits in Combination With Switching to Higher Sulfur Coal Many CAIR units are projected to install FGD to reduce SO <sup>2</sup> emissions. As discussed above, operation of dry or wet FGD reduces SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> emissions. However, some units installing FGD for CAIR may choose to switch to a higher sulfur coal at the time they install FGD. Dry FGD reduces SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> sufficiently to most likely mitigate any increase from the higher sulfur coal. Considering the lower SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> removal efficiency of wet FGD, however, the potential exists for sulfuric acid emissions to increase from units that install wet FGD and switch to higher sulfur coal. 3. Summary of Combinations of CAIR SCR and/or FGD Retrofits and Coal Switches That May Increase Sulfuric Acid Emissions The following table summarizes combinations of SCR and/or FGD control retrofits and coal switches that may occur as a result of CAIR, and identifies which of these combinations could lead to increases in sulfuric acid emissions significant enough to trigger the NSR threshold. Table III-1.—Combinations of CAIR SCR and/or FGD and Coal Switches That May Increase Sulfuric Acid Emissions Combinations of SCR and/or FGD and coal switches Increase in sulfuric acid emissions? Install SCR Possible. Install SCR and switch from high to low sulfur coal No. Install SCR with wet FGD (no coal switch) No. Install SCR with wet FGD and switch to higher sulfur coal Possible. Install wet FGD (no coal switch) No. Install wet FGD and switch to higher sulfur coal Possible. Install SCR and dry FGD No. Install dry FGD No. 4. Technology Options Available for Mitigating Sulfuric Acid Emission Increases Several technology options are available for mitigating sulfuric acid emission increases from CAIR retrofit projects. These include: • Injecting alkali materials into the furnace; • Injecting alkali postfurnace; • Injecting ammonia; • Fuel switching (e.g., firing lower sulfur coal); • Selecting specialized SCR catalyst with a low SO <sup>3</sup> conversion rate; • Installing wet ESP; and • Installing FGD. The Agency anticipates that some CAIR sources may choose to install emerging multipollutant control technologies designed to reduce not only SO <sup>2</sup> and NO <sup>X</sup> but SO <sup>3</sup> and other pollutants as well. Generally, sources choosing to employ such technologies would do so if they found it to be economical. Although EPA does not endorse the purchase or sale of any specific products and services mentioned, example multipollutant technologies include: • Powerspan ECO Technology; and • Mobotec USA Inc. ROTAMIX System. 5. Analysis of SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> Mitigation Costs and Timing Impacts for CAIR SCR and/or Wet FGD Projects *Cost Modeling for SO* 3 */H* 2 *SO* 4 *Controls* . The Agency used the Integrated Planning Model
(IPM)6 to provide an upper-end estimate of the possible cost impacts for CAIR units that may install SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> controls. The EPA does not believe this analysis provides a true estimate of the costs to CAIR units of the *NY* v. *EPA* decision. Instead, EPA believes this analysis significantly overstates the potential costs. However, because this analysis shows that even when the costs are significantly overestimated they do not impact the analyses done for the final CAIR, EPA determined that a more refined analysis was not necessary to address petitioner's concerns. 6 The IPM is a multiregional, dynamic, deterministic linear programming model of the U.S. electric power sector. The Agency uses IPM to examine costs and, more broadly, analyze the projected impact of environmental polices on the electric power sector in the 48 contiguous States and the District of Columbia. The EPA believes this analysis overstates the likely true cost impact because, as explained below, it relies on several conservative assumptions. For example, we assumed that every unit that is projected to install SCR and/or wet FGD will incur increased costs for SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation. Our cost analysis is based on the assumption that each unit that retrofits SCR and/or wet FGD will install wet ESPs for SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation. 7 The Agency believes that the choice of SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation method would depend greatly on the specifics of the affected sources, thus it is difficult to predict control choices. For this cost analysis, EPA chose to model costs based on wet ESP because we believe the costs of this technology are representative of the costs of technologies that sources might choose to install. 7 Although the Agency based this analysis on installation of wet ESP, the Agency is not making any determination or prediction regarding what the specific PSD/NSR requirements might be for these projects. The EPA performed an IPM sensitivity analysis in which we added costs for wet ESP to every unit that installs SCR and/or wet FGD. We based this sensitivity analysis on the IPM model run that includes the CAIR, Clean Air Mercury Rule
(CAMR)and Clean Air Visibility Rule
(CAVR)requirements. Note that the IPM modeling for the final CAIR highly cost-effectiveness determination does not include the CAMR and CAVR requirements. However, the Agency subsequently conducted IPM modeling that reflects CAIR, CAMR and CAVR. The IPM analysis discussed in today's notice (which examines the possible cost impacts of SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation) is based on the modeling that includes CAIR, CAMR and CAVR because that modeling best reflects current requirements. 8 8 The two model runs (the final CAIR modeling or the subsequent modeling with CAMR and CAVR) use the same underlying base case assumptions in the same modeling platform. In other words, the two runs are based on identical assumptions for parameters such as (this is not an exhaustive list): EGU inventory, fuel prices, impacts of the national title IV SO <sup>2</sup> program, NO <sup>X</sup> SIP program, State-specific programs, and NSR settlements. Note that projected marginal costs for CAIR SO <sup>2</sup> and NO <sup>X</sup> reductions are about $100 per ton less in the CAIR/CAMR/CAVR modeling than in the final CAIR modeling, due to interactions between the three programs. As noted above, this modeling—the SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation IPM sensitivity modeling—overstates the possible cost impacts to CAIR units for several reasons. As discussed above, only the following three combinations of CAIR SCR and/or wet FGD retrofits might increase sulfuric acid emissions significantly to trigger the NSR threshold: units installing SCR alone (without switching to lower sulfur coal); units installing SCR with wet FGD and switching to higher sulfur coal; and, units installing wet FGD alone and switching to higher sulfur coal. The IPM sensitivity analysis conservatively assumes SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation costs are incurred by every unit projected to retrofit SCR and/or wet FGD. We note, however, that based on EPA's IPM modeling, for the first and second CAIR phases, respectively, only 16 percent and 11 percent of total CAIR-affected generating capacity (i.e., capacity of units in CAIR States with capacity greater than 25 MW) are projected to retrofit in any of these three combinations that might increase sulfuric acid emissions significantly to trigger the NSR threshold. Also, it is possible that units that inject SO <sup>3</sup> to improve cold-side ESP performance would cease injecting SO <sup>3</sup> after installing SCR which could result in the net SO <sup>3</sup> increase being insufficient to trigger NSR (as discussed above), however the Agency's IPM sensitivity does not take into account this possibility. Additionally, the IPM sensitivity model run overstates the cost impacts to CAIR units because that modeling added SO <sup>3</sup> /sulfuric acid mitigation costs for all units retrofitting SCR and/or wet FGD, including retrofits that are projected to occur prior to commencement of CAIR retrofits (the Agency assumes that retrofits occurring prior to 2007 do not result from CAIR, but rather from existing programs such as the title IV SO <sup>2</sup> program and the NO <sup>X</sup> SIP Call, however the IPM modeling does not account for this distinction). Further, our analysis overstates the cost impacts to CAIR units because the modeling includes retrofits that occur in the base case (without CAIR) and also includes the CAMR and CAVR requirements. Further, in the IPM sensitivity analysis we assumed units would incur costs for year-round operation of wet ESP in all CAIR States, including the States that are only required to make ozone season NO <sup>X</sup> reductions for CAIR. Finally, the IPM sensitivity run overstates the cost impacts because we added costs for wet ESP to each affected unit although SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation options are available that are less expensive than wet ESP. Nonetheless, the Agency's cost analysis assumed that every unit that is predicted to install SCR and/or wet FGD in the CAIR/CAMR/CAVR modeling will incur additional costs for year-round operation of a wet ESP, in order to provide an upper-end estimate of the possible cost impacts of SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation. Table III-2 shows the results of this analysis. It compares the SO <sup>2</sup> and NO <sup>X</sup> marginal costs in the SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation sensitivity analysis to the marginal costs in the final CAIR modeling (Table III-2 also shows marginal costs from the modeling that included CAIR, CAMR and CAVR). 9 In the sensitivity analysis, the costs of SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation are reflected in the marginal costs of SO <sup>2</sup> and NO <sup>X</sup> control. 9 As in the CAIR NFR (70 FR 25198), the Agency reports cost effectiveness results for both of the CAIR phases although the Phase I CAIR control levels were determined based on feasibility rather than cost effectiveness. Table III-2.—SO <sup>2</sup> and NO <sup>X</sup> Estimated Marginal Cost [1999$ per ton] 1 SO <sup>2</sup> Annual 2010 2015 NO <sup>X</sup> Annual 2009 2015 CAIR modeling used in final CAIR cost-effectiveness analysis $700 $1,000 $1,300 $1,600 CAIR/CAMR/CAVR modeling 600 900 1,200 1,500 Sensitivity analysis with SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation (based on CAIR/CAMR/CAVR modeling) 700 900 1,600 2,000 1 EPA IPM modeling is available in the docket. Projected costs are rounded to the nearest hundred dollars. As shown in Table III-2, projected SO <sup>2</sup> marginal costs in the SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation sensitivity modeling are lower than the SO <sup>2</sup> marginal costs in the final CAIR modeling for 2015 and are about the same as the costs in the final CAIR for 2010. This does not imply that the added costs of SO <sup>3</sup> H <sup>2</sup> SO <sup>4</sup> mitigation are so small as to have no effect on the marginal costs of SO <sup>2</sup> reduction. Rather, the added costs of SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation increase the SO <sup>2</sup> marginal cost from the level in the CAIR/CAMR/CAVR run a small amount. As explained above, marginal cost levels in CAIR/CAMR/CAVR modeling are lower than costs in the modeling in the CAIR final rulemaking. In the SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation sensitivity analysis, the 2010 cost is increased to about the level in the final CAIR modeling, and the 2015 cost increase is small enough that it is not apparent when the costs are rounded to the nearest hundred dollars. Including the added costs of SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation, the projected marginal costs of SO <sup>2</sup> reduction under CAIR remain at the lower end of the reference range of marginal costs cited in the Agency's CAIR cost-effectiveness determination. The range of marginal costs cited in CAIR is $600 to $2,200 per ton of SO <sup>2</sup> removed (70 FR 25201-25204). As shown in Table III-2, projected NO <sup>X</sup> marginal costs in the SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation sensitivity are higher than the costs in the final CAIR modeling. However, including the added costs of SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation, the projected NO <sup>X</sup> marginal costs remain at the lower end of the reference range of marginal costs cited in the Agency's cost-effectiveness determination. The range of marginal costs cited in CAIR is $2,000 to $19,600 per ton of annual NO <sup>X</sup> removed (70 FR 25208-25210). For the reasons discussed above, the Agency's analysis likely overstates the cost impacts of SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation. Nonetheless, even with these projected cost impacts, the marginal costs remain at the low end of the range of costs cited in the final CAIR highly cost-effectiveness determination (70 FR 25201-25204, 25208-25210). Thus, that determination is not affected by the possible costs that may be incurred by units installing SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation technologies. The Agency believes that average costs of SO <sup>2</sup> and NO <sup>X</sup> control also would not increase significantly enough to impact the CAIR cost-effectiveness determination, because the projected marginal costs do not increase enough to impact the CAIR analysis. The Agency discusses below its evaluation of the feasibility of installing SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation measures, and the impacts of NSR analysis. *Feasibility and Timing Analysis.* In its CAIR analysis, the Agency evaluated the feasibility of installing projected SO <sup>2</sup> and NO <sup>X</sup> control retrofits in the CAIR timeframe. In particular, EPA examined the availability of boilermaker labor to install retrofits during the period when the CAIR retrofits will occur and determined that sufficient labor will be available (70 FR 25215-25225). The Agency's CAIR analysis was discussed in detail in a TSD entitled “Boilermaker Labor and Installation Timing Analysis,” OAR-2003-0053-2092 (“final CAIR boilermaker TSD”). The Agency has evaluated the potential impacts on the CAIR timeline from installation of SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation technologies. Specifically, we examined the impact of installing wet ESP on the availability of boilermaker labor during the time when control retrofits will be installed for the two CAIR phases. The EPA's analysis assumed that units that might experience sulfuric acid emission increases greater than the NSR threshold while incorporating NO <sup>X</sup> and/or SO <sup>2</sup> controls for CAIR would choose to install wet ESP, which is a conservative assumption because SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation measures are available that would require less boilermaker labor than wet ESP. For this boilermaker labor analysis, the Agency used the identical assumptions regarding boilermaker availability factors ( *i.e.* , boilermaker sources, population, average annual work hours, activity periods, and duty rates) that we used in the boilermaker analysis for the final CAIR. These factors are defined in the final CAIR boilermaker TSD. For today's notice, the Agency based its boilermaker analysis on the generating capacity that is projected to install NO <sup>X</sup> and SO <sup>2</sup> controls that may increase sulfuric acid emissions (the three combinations of SCR and/or wet FGD retrofits and coal switches identified in Table III-1). The EPA examined the capacity of retrofits that are projected to occur during the time period when CAIR retrofits would occur for the two CAIR phases ( *i.e.* , during the years 2007 through 2015 inclusive). This analysis includes retrofits projected to occur as result of the CAIR, CAMR and CAVR policies as well as retrofits for base case policies ( *i.e.* , retrofits for existing regulatory requirements such as the title IV SO <sup>2</sup> program and the NO <sup>X</sup> SIP Call) because some base case retrofits will occur during the time period 2007 through 2015. In its analysis for the final CAIR, the Agency determined that adequate boilermaker labor would be available to complete the CAIR NO <sup>X</sup> and SO <sup>2</sup> control retrofits in the CAIR timeline, with sufficient contingency factors available to offset possible additional labor needs due to unforeseen events. In the final CAIR, EPA considered a number of scenarios that included different assumptions for boilermaker duty rates ( *i.e.* , the amount of time required for a boilermaker to install control equipment), electricity demand and gas prices. In the most conservative scenario analyzed, EPA determined that there would be a 14 percent boilermaker labor contingency ( *i.e.* , 14 percent more labor would be available than the amount required to install the controls). The boilermaker duty rates used for this case were provided by a commenter on the CAIR, were well above the levels determined to be appropriate in a detailed study conducted by EPA, and, based on EPA's investigations, reflected the worst-case assumptions for the boilermaker labor requirements associated with building air pollution controls. If the boilermaker requirements are estimated using EPA's boilermaker duty rates, the available contingency would be higher. The revised boilermaker labor analysis that the Agency conducted for today's notice, which takes into account boilermaker labor required to install wet ESP, indicates that adequate boilermaker labor will be available even considering the additional boilermakers that may be needed to install the wet ESP. Considering the same assumptions that yielded a 14 percent contingency in the final CAIR along with additional boilermakers needed to install wet ESPs, EPA determined that there would be a 4 percent contingency. Again, if the boilermaker requirements are estimated using EPA's boilermaker duty rates, the available contingency would be higher. This analysis is conservative in that it assumes that in all cases where companies install equipment to mitigate SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> increases, they install wet ESPs, which use more boilermakers than other options such as sorbent injection. The remaining contingency factors are still adequate (although reduced). Thus, the NO <sup>X</sup> and SO <sup>2</sup> control retrofits projected to be installed for CAIR can be completed in the available time, even considering the potential additional labor needs for SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation. Note that any SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> controls for CAIR projects can be retrofit concurrently with the SO <sup>2</sup> and NO <sup>X</sup> retrofits, and no additional time would be needed. See further discussion of timing in the permitting section, below. Details of EPA's revised boilermaker labor analysis are in a TSD in the docket entitled “Impact on CAIR Analyses of D.C. Circuit Decision in *New York* v. *EPA* .” The Agency believes that the impacts of mitigating the potential emission increases, or undertaking NSR review for these units, are not substantial enough to alter the CAIR highly cost-effective determination or the feasibility and timing analysis. Implications of NSR analysis for such units are discussed further below. 6. Increases in Carbon Monoxide and Unburned Carbon (Solid Particulate) Emissions From Combustion Controls Combustion controls that may be installed for CAIR to reduce NO <sup>X</sup> emissions include low NO <sup>X</sup> burners
(LNB)and overfire air (OFA). Both LNB and OFA reduce NO <sup>X</sup> generation rates by changing the combustion process. Either one or both technologies may be installed on a generating unit to control NO <sup>X</sup> emissions. Depending on the boiler design, these changes may result in an increase in emissions of carbon monoxide
(CO)and unburned carbon (solid particulate), although the potential for increases significant enough to trigger the NSR threshold exists only with the use of OFA (because LNB does not affect the combustion process extensively). These emissions increases can be minimized by using more modern control designs and techniques. 10 11 12 These increases can also be minimized by using less-aggressive OFA flow rates. 13 The NO <sup>X</sup> removal efficiencies for combustion controls assumed in EPA's CAIR analysis are not aggressive. 14 The Agency believes that units projected to install combustion controls can opt for moderate levels of OFA flow rates and still achieve the NO <sup>X</sup> reduction levels projected in our CAIR analysis, without causing significant increases in CO and unburned carbon emissions. Therefore, given the conservative removal efficiency assumptions in EPA's original analysis, there would be no additional significant costs associated with mitigating CO emissions to avoid NSR when combustion controls are added. 10 T. Steitz, *et al.* , “Wall Fired Low NO <sup>X</sup> Burner Evolution for Global NO <sup>X</sup> Compliance,” Foster Wheeler Web site, *http://www.fwc.com/publications/tech_papers/index.cfm#14905467952D7FCAFC 2A5B206EAE10F0* , Web site accessed on September 30, 2005. 11 K. McCarthy, *et al.* , “Improved Low NO <sup>X</sup> Firing Systems for Pulverized Coal Combustion,” Foster Wheeler Web site, *http://www.fwc.com/publications/tech_papers/index.cfm#14905467952D7FCAFC 2A5B206EAE10F0,* Web site accessed on September 30, 2005. 12 “Reducing Emissions of Nitrogen Oxides Via Low-NO <sup>X</sup> Burner Technologies,” Clean Coal Technology, The Department of Energy, Topical Report No. 5, September 1996. 13 A. Kokkinos, *et al.* , “B&W's Experience Reducing NO <sup>X</sup> Emissions in Tangentially-Fired Boilers—2001 Update,” Power-Gen International 2001, December 11-13, 2001, Las Vegas, Nevada. 14 The NO <sup>X</sup> removal efficiency for each type of combustion control used in EPA's analysis for CAIR was estimated as an average of the reported efficiencies for a large number of units equipped with these controls. In a unit equipped with both LNB and OFA, LNB provides a greater part of the overall NO <sup>X</sup> removal. Certain affected CAIR sources are projected to install both combustion controls and SCR. These sources have the option to use combustion control designs ensuring minimal CO and unburned carbon impacts, with SCR compensating for the possible reduced performance of combustion controls. Considering the potential of SCR technology to provide 90 percent NO <sup>X</sup> reduction with a minimum NO <sup>X</sup> rate of 0.06 lb/MMBtu, most of these sources would be able to use this strategy and avoid use of aggressive combustion control designs. The affected CAIR sources also have the option to use an advanced OFA system with the potential to achieve high NO <sup>X</sup> reduction levels, with no increases in CO and unburned carbon levels. This technology utilizes rotating opposed fire air
(ROFA)and has been installed or demonstrated at several plants worldwide. 15 15 MOBOTECUSA Web site, *http://www.mobotecusa.com/* . The Agency believes that there will be no increase in cost to CAIR units for using good combustion practices to mitigate CO and unburned carbon increases, because industry generally uses such practices already. Implementation of these practices would not affect the Agency's CAIR highly cost-effectiveness determination or the feasibility and timing analysis. In addition, the implications of NSR analysis for such units are relatively minor, as discussed further below. The Agency believes that the impacts of either mitigating the potential emission increases, or undertaking NSR review for these units, are not substantial enough to affect the CAIR highly cost-effective determination or the feasibility and timing analysis. Implications of NSR analysis for such units are discussed further below. 7. Increases in Direct PM2.5 Resulting From Fugitive Emissions From Storage or Handling of Lime, Limestone, or FGD Waste After Installation of Dry or Wet FGD As discussed above, dry and wet FGD are effective SO <sup>3</sup> /H <sup>2</sup> SO <sup>4</sup> mitigation options. A separate consideration, however, is the potential for increased emissions of direct PM (including PM2.5) resulting from the storage and handling of lime or limestone for the FGD and from hauling FGD waste. The EPA believes that operation of FGD will not result in significant increases of emissions of direct PM (including PM2.5). Fugitive PM emissions resulting from the storage and handling of lime or limestone and from waste hauling associated with FGD operation are minimal since most lime and limestone will be stored in covered structures with particulate controls, lime and limestone will be transported in covered vehicles, and particulate emissions mitigation techniques, including spraying near storage areas, hauling roads, and waste hauling trucks, will be employed. Fugitive emissions could result from dust recirculation due to truck hauling, but these emissions are also not significant enough to trigger NSR. The Agency believes that the impacts of either mitigating these small potential emission increases, or undertaking NSR review for these units, are not substantial enough to affect the CAIR highly cost-effective determination or the feasibility and timing analysis. 8. Collateral Air Pollutant Emissions From Units Switching From High to Low Sulfur Coals A switch from high-to low-sulfur coals is an option projected to be used by certain CAIR sources for SO <sup>2</sup> control. In some cases, modifications to the existing equipment may become necessary to maintain compatibility with the boiler and associated systems. One of the more common modifications required is the need to restore the existing ESP performance, which may be degraded due to the high-resistivity ash generated from firing of low-sulfur coals (if ESP performance is not restored, emissions of PM might increase). In general, use of a flue gas conditioning system fully restores the ESP performance to levels obtained from firing of high-sulfur coals. The impact of coal switching on the existing plant equipment would vary with the amount of switch. For example, if only a portion of the existing high-sulfur coal is replaced with the new low-sulfur coal, the impact may be minimal. Also, use of certain types of low-sulfur coals may even have a beneficial impact on some of the NSR-regulated pollutants. For example, use of western sub-bituminous coals may result in a reduction in the CO and unburned carbon levels, because of the high volatile contents of such coals. In the CAIR analysis, EPA assumed that the sources opting to switch to low-sulfur coal would either select compatible coals or provide modifications where required to avoid any adverse impacts on their boilers, including minimization of any increases in air emissions. The EPA included costs for such modifications in its estimates for the CAIR implementation, which were based on the coal switch experience for the power industry. Therefore, no further analysis is necessary. 9. Summary of Section III.B. EPA's IPM modeling predicts that some CAIR units will add controls with the potential to increase collateral emissions of NSR-regulated pollutants. However, the Agency has determined that for each of the NO <sup>X</sup> and SO <sup>2</sup> controls on which EPA based its CAIR highly cost-effectiveness determination, there are technology options available to mitigate potential collateral increases of NSR regulated pollutants such that many sources, looking to comply with the CAIR requirements, would not trigger NSR review for potential collateral increases (however, some sources may not be able to ensure mitigation of all collateral increases). Further, although some additional cost may be associated with mitigation measures, EPA's analysis showed that these costs do not change the conclusions of EPA's highly cost-effectiveness determination. In addition, implementing these mitigation measures will not affect the feasibility of implementing the CAIR reductions in the required timeframe. Options exist that would allow units to meet the CAIR deadlines without changing plans to stagger PCP projects. For example, a unit planning to install SCR first and FGD later could choose to use sorbent injection technology to mitigate SO <sup>3</sup> /H <sup>2</sup> SO <sup>3</sup> during the time between installation of the SCR and the FGD. C. Potential Impact of NSR Permitting Although the above analysis shows that sources installing controls for CAIR generally will have options to avoid triggering NSR review for potential collateral increases, EPA also analyzed the potential impact on its CAIR analyses of sources whose projects could result in a net emissions increase despite mitigative measures that might be taken, and might therefore apply for and obtain the necessary NSR permits to address such increase. Accordingly, EPA analyzed whether sources undergoing NSR permitting would have adequate time to obtain the preconstruction permit and whether any controls required would impact EPA's highly cost-effective analysis done for CAIR. The Agency intends to work with the States to quickly resolve any questions regarding permitting of CAIR pollution control projects, and will provide technical assistance when requested to facilitate permitting. In its analysis for the final CAIR, the Agency assumed that affected sources would have about 22 months available for preconstruction activities ( *e.g.* , permitting, planning, conceptual design, engineering, financing, and procurement) for the first phase of CAIR control retrofits. The 22 months is based on the time from the CAIR promulgation date (March 10, 2005) until about 4 months after the SIP submission date (about mid-January 2007). 16 The *New York* v. *EPA* judicial decision was issued on June 24, 2005. As a result of that decision, either CAIR sources will need to mitigate emissions through one of the various options discussed above, or they may choose to apply for NSR permits. Sources that elect to obtain NSR permits then would have almost 19 months for NSR review for the first CAIR phase (from the date of the *New York* v. *EPQ* decision until about mid-January 2007). The Agency believes that this is adequate time to perform NSR review, as explained further below, thus the CAIR timeline would not be impacted. 16 “Boilermaker Labor Analysis and Installation Timing,” March 2005, discusses the Agency's projected schedules for CAIR SCR and FGD retrofits (OAR-2003-0053-2092). In the CAIR, the Agency determined highly cost-effective amounts of emission reductions based on modeled costs of SO <sup>2</sup> and NO <sup>X</sup> mitigation, using IPM. The IPM cost modeling used in EPA's analysis reflects the capital and operations and maintenance costs of control technologies. The modeling does not include costs associated with permitting. Costs for permitting are insignificant compared to costs of constructing and operating these controls technologies. Prior to the D.C. Circuit decision to vacate the PCP provisions in the NSR program, EGUs desiring to use the PCP exclusion were required to either provide notice to the Administrator (for certain projects listed in the regulations) or submit a permit application to obtain approval to use the exclusion. This process had requirements very similar to those that apply to sources subject to NSR review. The basic steps for sources undergoing NSR review are: a. Preparation of the permit application and participation in any pre-permit application meetings; b. Issuance of permit application completeness determination by the regulatory agency; c. Development and negotiation of the draft permit; d. Opportunity for public notice and comment on the draft permit; e. Response by the regulatory agency to public comments; and f. Possible administrative and judicial appeals. Of these steps, the bulk of the effort is concentrated in the beginning steps with the preparation of the permit application and collection and analysis of the data necessary to demonstrate that the project would not present problems with the NAAQS. The PCP exclusion did not excuse a source from undergoing a similar analysis in order to obtain the PCP determination. Specifically, under the new source review rules of 2002 (67 FR 80186), a source seeking to use the PCP provisions for one of the listed technologies would automatically qualify for the exclusion if it could demonstrate that there was no adverse air quality impact, that is, if it would not cause or contribute to a violation of NAAQS or PSD increment, or adversely impact an air quality related value (AQRV), such as visibility, that had been identified for a Federal Class I area by a Federal Land Manager (FLM). In performing the air quality analysis under the PCP provision, the procedures established for conducting air quality analysis in conjunction with typical NSR permitting were used. As such, the up front burden associated with undergoing NSR review is comparable to the burden to which a source requesting a PCP exclusion would have been subject. Once the permit application is complete, whether processed as a PCP exclusion request or as a formal PSD permit application, the processing by the permitting authority usually does not take any longer under the formal PSD process than under the previous PCP exclusion process. Typically, in the formal NSR permitting process, once the application is submitted to the permitting authority, there is a process during which the draft permit is developed and published to give the public an opportunity to comment on the draft permit. Depending on the comments received, some changes to the draft permit may be made and a final permit would then be issued to the source. Based on the permitting authorities' experience, this process typically takes approximately six to eight months. In the case of permits issued for the construction of pollution control projects on CAIR units, we see no reason why the process should require a longer time period than is normally required. In addition, we do not believe that the PSD requirement for submitting pre-application monitoring data will cause a delay in submitting the required PSD permit applications as the petitioner alleges. The relevant provision which requires the applicant to include 12 months of continuous ambient air quality data allows applicants to rely on ambient air quality data that has already been collected and is representative of the air quality in the vicinity of the affected source. Moreover, such data is only required when the source's emissions increase is predicted to exceed the prescribed significant monitoring value for that pollutant. See 40 CFR 52.21(i)(5). Thus, sources generally will not have to take the time to collect such data on their own when it is required. In the few cases, if any, where it is the applicant's burden to collect the data, we believe they will have adequate time to do so while the overall project to comply with CAIR is being developed without delaying the necessary permit application. For sources that requested a PCP exclusion from the list of approved projects (67 FR 80246), the timeline could have been very similar in duration to the one described above for sources undergoing NSR review. The projects included on the list were presumed to be environmentally beneficial based on the premise that the source seeking the PCP exclusion would design and operate the controls in a manner that would be consistent with proper industry, engineering, and reasonable practices, and that the source would minimize increases in collateral pollutants within the physical configuration and operational standards usually associated with the emissions control device or strategy. The source seeking the PCP exclusion would have been required to certify that this was true in the notification sent to the reviewing authority. It is important to highlight that the environmentally beneficial determination for the listed projects was a presumption, and as such, it could be rebutted in cases in which a reviewing authority determined that a particular proposed PCP project would not be environmentally beneficial. Before a source requesting a PCP exclusion could have begun actual construction of the PCP, it was required to submit a notice to the reviewing authority that included the following information (and depending on the reviewing authority's requirements, this information could have been submitted with a part 70, part 71 or other SIP-approved permit application such as a minor NSR permit application):
(1)A description of project;
(2)an analysis of the environmentally beneficial nature of the PCP, including a projection of emissions increases and decreases (speciated, using an appropriate emissions test for the emissions unit); and
(3)a demonstration that the project will not have an adverse air quality impact. Often, a screening model could be used to estimate the ambient impacts of the increase from the facility as a result of the PCP. Special attention would have been given in cases where a FLM had already identified adverse impacts for an AQRV. In such cases, the facility requesting the PCP exclusion would have been expected to record and consider any information that the FLM had made available concerning the adverse effects, to help determine whether the pollutant impacts from the collateral emissions increase had the potential to cause further adverse impacts. If the requested PCP was included in the list of projects presumed to be environmentally beneficial, the source requesting the PCP exclusion would have been allowed to begin construction on the PCP immediately upon submitting the required notice to the reviewing authority. However, if the reviewing authority determined that the source did not qualify for a PCP exclusion, the source might have been subject to a delay in the project or an order to not undertake the project. If the reviewing authority, upon receiving the notification of using the PCP exclusion, determined that an air quality impacts analysis was reasonably necessary, it was entitled to request more information from the source, including additional local or regional modeling. Pollution control projects of the magnitude at issue here will require large capital expenditures and significant engineering lead times. We believe that in most cases, the internal procedures within each company to request, approve, and allocate the necessary funding and then design and construct the control equipment will be at least as long as the average permit application and approval process. *Additional requirements that may result from NSR review.* As discussed in previous sections, sources installing controls to comply with CAIR that experience collateral emissions increases of some NSR regulated pollutants likely would have requested a PCP exclusion. In particular, sulfuric acid mist emissions and CO emissions are the two pollutants expected to be of most interest. For emissions of CO, the Agency is aware of previous PSD permits that have been processed by permitting authorities that demonstrated no NAAQS problems, while requiring no additional add-on controls for the CO emissions. The PSD permits given to these sources included Best Achievable Control Technology
(BACT)emissions limits for CO where in most cases such limits did not previously exist. Most of these limits have been set at or near the level where the utility has historically operated or was anticipated to operate. This is the case because there is no technically feasible add-on control technology for controlling CO emissions from coal-fired boilers other than good combustion practices. For emissions increases of sulfuric acid mist, NSR permitting analysis treats sulfuric acid mist as a NSR-regulated pollutant and also as a component of PM <sup>2.5</sup> (a criteria pollutant). The Agency conducted an analysis of the information available for EGUs that have undergone NSR review and that included a determination of controls (BACT or Lowest Achievable Emission Rate (LAER)) for sulfuric acid mist. The analysis showed that pollution prevention measures (such as low sulfur fuel) and add-on controls (such as flue gas desulfurization or FGD) were cited in about two thirds of the determinations, while about one third resulted in no additional control. As previously stated, both switching to low sulfur coal and the use of FGD are common techniques available for CAIR units to minimize collateral emissions increases due to the installation of CAIR-related controls. As a result, we expect that a source going through NSR for significant net emissions increases in sulfuric acid mist due to CAIR controls would be required to install technology similar, if not identical, to those presented here as available mitigation techniques to avoid NSR review. Because sulfuric acid mist emissions are also a component of PM <sup>2.5</sup> , EPA also looked at what, if any, additional PM <sup>2.5</sup> controls would be required for sources required to undergo NSR should a significant emissions increase of PM <sup>2.5</sup> occur. For CAIR emissions units located in non-attainment areas, we also believe that the result of the LAER analysis for these units will result in control technologies similar, if not identical, to those listed as available mitigation techniques. In addition to the LAER requirements, CAIR sources required to meet nonattainment area NSR would be required to obtain emissions reductions to offsets their significant emissions increase of PM <sup>2.5</sup> emissions as part of non-attainment NSR permit process. We believe PM fine offsets will be widely available for any of these projects located in non-attainment areas. In the PM Implementation Rule (70 FR 66042) we proposed to allow units to use decreases in PM fine precursor emissions as offsets for direct PM fine emission increases. Units installing controls to comply with CAIR will have very large decreases in PM fine precursors (SO <sup>2</sup> and NO <sup>X</sup> ). These decreases are so large that we believe the decreases in PM fine precursor emissions from other CAIR units will provide sufficient offsets for the significantly lower potential increases in direct PM fine emissions. As such, we believe that the impact for undergoing NSR review on these sources would be minimal, as described above. For projects located in attainment areas, a situation similar to when a source is required to install controls for acid mist is expected. That is, when a source in an attainment area goes through NSR review for PM <sup>2.5</sup> as a result of a collateral increase due to the addition of CAIR controls, we expect the required control technology to be similar, if not identical, to those listed as available mitigation techniques for sources wanting to avoid NSR review. As such, we believe that the impact for undergoing NSR review on these sources would be minimal, as described above. In conclusion, the Agency believes that the impacts of choosing to undertake NSR review for these units are not substantial enough to affect the CAIR highly cost-effective determination or the feasibility and timing analysis. The EPA generally does not believe that the PCP requirements under NSR will pose a problem. This is because either companies will make control decisions that will not result in collateral pollution increases or the NSR process will not delay installation of pollution controls. Even if there were a small number of cases in which NSR requirements delayed control installations beyond the compliance dates for CAIR, EPA does not believe that this would change its conclusions about the cost effectiveness of the required emission reductions. The cost effectiveness is not significantly impacted because the trading mechanisms within CAIR provide flexibility if small numbers of sources are unable to install controls by the compliance deadlines. IV. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review Under Executive Order 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. The Order defines “significant regulatory action” as one that is likely to result in a rule that may:
(1)Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities;
(2)create a serious inconsistency or otherwise interfere with an action taken or planned by another agency;
(3)materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or
(4)raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order. Pursuant to the terms of Executive Order 12866, OMB has determined that this is not a significant regulatory action. This notice takes comment on an aspect of the CAIR, but does not propose any modifications. B. Paperwork Reduction Act This action does not propose information collection request requirements under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 *et seq.* Therefore, an information collection request document is not required. 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. C. Regulatory Flexibility Act The Regulatory Flexibility Act generally requires an Agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedures Act or any other statute unless the Agency certifies 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 proposed rule on small entities, 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 part 121.);
(2)a 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. After considering the economic impacts of today's proposed rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. This notice does not impose any requirements on small entities. We are only announcing our decision to reconsider and request comment on a specific issue in the CAIR. We continue to be interested in the potential impacts of the rule on small entities and welcome comments on issues related to such impacts. 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 by State, local, and tribal governments, in the aggregate, or by the private sector, of $100 million or more in any 1 year. Before promulgating an EPA rule for which a written statement is needed, UMRA section 205 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's regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements. The EPA has determined that today's notice of reconsideration 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 1 year. Today's notice of reconsideration of the CAIR does not add new requirements that would increase the cost of the CAIR. Thus, today's notice of reconsideration is not subject to the requirements of sections 202 and 205 of the UMRA. In addition, EPA has determined that today's notice of reconsideration does not significantly or uniquely affect small governments because it contains no requirements that apply to such governments or impose obligations upon them. Therefore, today's notice of reconsideration is not subject to section 203 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.” This action does not have federalism implications. It would 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. The CAA establishes the relationship between the Federal Government and the States, and this action would not impact that relationship. Thus, Executive Order 13132 does not apply to this action. 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.” For the same reasons stated in the final CAIR, today's notice does not have tribal implications as defined by Executive Order 13175. It does not have a substantial direct effect on one or more Indian Tribes, since no tribe has implemented a federally-enforceable air quality management program under the CAA at this time. Furthermore, this action does not affect the relationship or distribution of power and responsibilities between the Federal Government and Indian Tribes. The CAA and the Tribal Air Rule establish the relationship of the Federal Government and tribes in developing plans to attain the NAAQS, and today's notice does nothing to modify that relationship. Because this notice does not have tribal implications, Executive Order 13175 does not apply. If one assumes a tribe is implementing a tribal implementation plan, the CAIR could have implications for that tribe, but it would not impose substantial direct costs upon the tribe, nor would it preempt tribal Law. Although Executive Order 13175 does not apply to the CAIR or this notice of reconsideration of the CAIR, EPA consulted with tribal officials in developing the CAIR. G. Executive Order 13045: Protection of Children From Environmental Health and Safety Risks Executive Order 13045: “Protection of Children From Environmental Health 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 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. This notice is not subject to Executive Order 13045 because it does not involve decisions on environmental health risks or safety risks that may disproportionately affect children. The EPA believes that the emissions reductions from the CAIR will further improve air quality and children's health. H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use This rule is not subject to Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355 (May 22, 2001)) because it is not a significant regulatory action under Executive Order 12866. I. National Technology Transfer Advancement Act Section 12(d) of the National Technology Transfer Advancement Act of 1995, Public Law 104-113, section 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 National Technology Transfer Advancement Act of 1995 directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards. Today's notice does not involve technical standards. Therefore, the National Technology Transfer and Advancement Act of 1995 does not apply. J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations Executive Order 12898, “Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations,” requires Federal agencies to consider the impact of programs, policies, and activities on minority populations and low-income populations. According to EPA guidance, 17 agencies are to assess whether minority or low-income populations face risks or a rate of exposure to hazards that are significant and that “appreciably exceed or is likely to appreciably exceed the risk or rate to the general population or to the appropriate comparison group.” (EPA, 1998). 17 U.S. Environmental Protection Agency, 1998. Guidance for Incorporating Environmental Justice Concerns in EPA's NEPA Compliance Analyses. Office of Federal Activities, Washington, DC, April, 1998. In accordance with Executive Order 12898, the Agency has considered whether the CAIR may have disproportionate negative impacts on minority or low income populations. The EPA expects the CAIR to lead to reductions in air pollution and exposures generally. Therefore, EPA concluded that negative impacts to these sub-populations that appreciably exceed similar impacts to the general population are not expected. For the same reasons, EPA is drawing the same conclusion for today's notice to reconsider a certain aspect of the CAIR. List of Subjects 40 CFR Part 51 Administrative practice and procedure, Air pollution control, Intergovernmental relations, Nitrogen oxides, Ozone, Particulate matter, Regional haze, Reporting and recordkeeping requirements, Sulfur dioxide. 40 CFR Part 96 Administrative practice and procedure, Air pollution control, Electric utilities, Nitrogen oxides, Reporting and recordkeeping requirements, Sulfur dioxide. Dated: December 22, 2005. Stephen L. Johnson, Administrator. [FR Doc. 05-24609 Filed 12-28-05; 8:45 am]
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  • 18 CFR 284
  • Pub. L. 109-58
  • 119 Stat. 594
  • 88 F.3d 1105
  • 285 F.3d 18
  • 172 F.3d 918
  • 83 F.3d 1424
  • 15 USC 3301-3432
  • 292 F.3d 831
  • 5 CFR 1320.11
  • 5 USC 601-612
  • 15 USC 717-717w
  • 42 USC 7101-7352
  • 43 USC 1331-1356
  • 36 CFR 7
  • 36 CFR 3.24
  • Pub. L. 89-366
  • Pub. L. 93-477
  • 413 F.3d 3
  • 40 CFR 2
  • 40 CFR 9
  • 13 CFR 121
  • Pub. L. 104-4
  • Pub. L. 104-113
  • 40 CFR 51
  • 40 CFR 96
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