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Code · REGISTER · 2007-06-13 · Office of Inspector General, Department of the Interior · Notices

Notices. Notice; corrections

89,616 words·~407 min read·/register/2007/06/13/07-2948

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BILLING CODE 7590-01-P PRESIDENT'S COUNCIL ON INTEGRITY AND EFFICIENCY Senior Executive Service Performance Review Board Membership AGENCY: Office of Inspector General, Department of the Interior. ACTION: Notice; corrections. SUMMARY: The Office of Inspector General, Department of the Interior, published a document in the **Federal Register** of December 5, 2006, concerning the membership of the Senior Executive Service Performance Review Board for the President's Council on Integrity and Efficiency.
The document should also have included the Executive Council on Integrity and Efficiency. FOR FURTHER INFORMATION CONTACT: Eric M. Lippold, 703-487-5371 Corrections. In the **Federal Register** of December 5, 2006, in FR Doc. E6-20548, on page 70570, in the third column, correct the “Heading” caption to read: PRESIDENT'S COUNCIL ON INTEGRITY AND EFFICIENCY EXECUTIVE COUNCIL ON INTEGRITY AND EFFICIENCY. In the **Federal Register** of December 5, 2006, in FR Doc. E6-20548, on page 70570, in the third column, correct the “Summary” caption to read:
SUMMARY: This notice sets forth the names and titles of the current membership of the President's Council on Integrity and Efficiency
(PCIE)and Executive Council on Integrity and Efficiency
(ECIE)Performance Review Board as of October 2, 2006. In the **Federal Register** of December 5, 2006, in FR Doc. E6-20548, on page 70570, in the third column, correct the “Supplementary Information” caption to read: I. Background The Inspector General Act of 1978, as amended, created the Offices of Inspectors General as independent and objective units to conduct and supervise audits and investigations relating to Federal programs and operations. Executive Order 12301 (March 26, 1981) established the President's Council on Integrity and Efficiency (PCIE). On May 11, 1992, Executive Order 12805 reaffirmed the PCIE and also established the Executive Council on Integrity and Efficiency (ECIE). Both councils are interagency committees chaired by the Office of Management and Budget's Deputy Director for Management. Their mission is to coordinate and enhance governmental efforts to promote integrity and efficiency and to detect and prevent fraud, waste, and abuse in Federal programs. The PCIE is comprised principally of the 29 Presidential appointed Inspectors General (IGs), ECIE members include the 32 Inspectors General appointed by their respective agency heads. II. PCIE/ECIE Performance Review Board Under 5 U.S.C. 4314(c)(1)-(5), and in accordance with regulations prescribed by the Office of Personnel Management, each agency is required to establish one or more Senior Executive Service
(SES)performance review boards. The purpose of these boards is to review and evaluate the initial appraisal of a senior executive's performance by the supervisor, along with any recommendations to the appointing authority relative to the performance of the senior executive. The current members of the PCIE/ECIE Performance Review Board, as of October 2, 2006, are as follows: Renee M. Pettis, Assistant Inspector General for Management. [FR Doc. E7-11377 Filed 6-12-07; 8:45 am] BILLING CODE 4310-10-P SECURITIES AND EXCHANGE COMMISSION [Release No. 34-55875; File No. SR-Amex-2006-170] Self-Regulatory Organizations; American Stock Exchange LLC; Order Granting Accelerated Approval of a Proposed Rule Change, as Modified by Amendment Nos. 1, 2, 3, and 4 Thereto, Relating to Procedures for At-Risk Cross Transactions June 7, 2007. I. Introduction On February 17, 2006, the American Stock Exchange LLC (“Amex” or “Exchange”) filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”) 1 and Rule 19b-4 thereunder, 2 a proposed rule change to adopt a new crossing procedure, the “at-risk cross,” as an alternative to the Exchange's existing facilitation cross procedure. On November 9, 2006, the Exchange filed Amendment No. 1 to the proposed rule change, and on December 1, 2006, the Exchange filed Amendment No. 2 to the proposed rule change. The proposed rule change, as modified by Amendment Nos. 1 and 2, was published for comment in the **Federal Register** on January 17, 2007. 3 On March 28, 2007, the Exchange filed Amendment No. 3 to the proposed rule change, and on May 3, 2007, the Exchange filed Amendment No. 4 to the proposed rule change. Amendment Nos. 3 and 4 to the proposed rule change were published for comment in the **Federal Register** on May 14, 2007 for a 15-day comment period. 4 The comment period ended on May 29, 2007. The Commission received no comments on the proposal. This order grants accelerated approval to the proposed rule change, as modified by Amendment Nos. 1, 2, 3, and 4. 1 15 U.S.C. 78s(b)(1). 2 17 CFR 240.19b-4. 3 *See* Securities Exchange Act Release No. 55068 (January 9, 2007), 72 FR 2044 (“Notice”). 4 *See* Securities Exchange Act Release No. 55719 (May 3, 2007), 72 FR 27155 (“Notice of Amendment Nos. 3 and 4”). II. Description of the Proposal The Exchange proposes to adopt an “at-risk cross” procedure for equity options by adding Commentary .03 to Amex Rule 950-ANTE(d). This new “at risk cross” procedure would supplement the existing facilitation cross procedure set forth in Commentary .02 to Amex Rule 950-ANTE(d) 5 The proposed at-risk crossing procedure would permit a floor broker, after satisfying all public customer orders, to execute a cross that is at-risk to the market on behalf of a member organization trading against its own customer's order between the quoted market, once priority has been established. 5 Commentary .02(c) to Amex Rule 950-ANTE(d) sets forth the facilitation cross procedures for options trading generally. Commentary .02(d) to Amex Rule 950-ANTE(d) sets forth conditions and procedures by which a member firm facilitating its own public customer's order is entitled to participate from its proprietary account as the contra-side of that order to the extent of 40 percent of the contracts remaining after public customers have been satisfied, provided the order trades at or between the quoted market. The at-risk cross transaction procedure would be available for use only by floor brokers attempting to cross an order of a public customer against an order from the same member organization, and the minimum eligible order size for the at-risk cross transaction would be 50 contracts. A floor broker attempting to execute an order as an at-risk cross would be required first to request bids and offers from the trading crowd for all components of the public customer order. 6 After the trading crowd has provided a quote, the floor broker would then represent the customer order to the trading crowd, indicating that it is a customer order and providing the order's size, side of the market, and a price, giving the customer the opportunity for price improvement. 6 The floor broker would be required to disclose on the order ticket for the public customer order all the terms of the order, including, if applicable, any contingency involving other options, underlying securities, or related securities. After the trading crowd has provided a quote in response to the customer order, the proposed rule would permit the floor broker to improve the trading crowd's quote on behalf of the member organization and thereby establish priority over the trading crowd at this new price. 7 The bid or offer on behalf of the member organization would be required to be one minimum price variation (“MPV”) away from the customer order. The floor broker could then attempt to consummate a cross transaction with the customer at that price. However, the cross transaction would be “at risk” to the market, because the trading crowd would still have the ability to break up the cross before its consummation, either by trading with the customer order at the customer's price or trading with the member organization's order at its attempted cross price. 7 At this point, the floor broker may alternatively decide to follow the procedures of Commentary .02(d) to Amex Rule 950-ANTE(d). Under the Exchange's existing facilitation crossing procedures, a member firm seeking to facilitate its own public customer's order is entitled to participate in the firm's proprietary account as the contra-side of that order up to 40 percent of the remaining contracts (the “Member Firm Guarantee”), provided that the order trades at a price that matches or improves the market, after public customer orders on the specialist's book or customer orders represented by a floor broker in the crowd have been filled. 8 Under the proposed at-risk crossing procedure, the floor broker on behalf of the member firm effectively would relinquish the Member Firm Guarantee in an attempt to cross the entire order. 8 *See* Commentary .02(d)(1) to Amex Rule 950-ANTE(d). III. Discussion After careful review, the Commission finds that the proposed rule change, as amended, is consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange and, in particular, with Section 6(b)(5) of the Act, 9 which requires, among other things, that the rules of a national securities exchange be designed to prevent fraudulent and manipulative acts and practices, to promote just and equitable principles of trade, to remove impediments to, and perfect the mechanism of, a free and open market and a national market system and, in general, to protect investors and the public interest. 10 9 15 U.S.C. 78f(b)(5). 10 In approving this proposed rule change, the Commission has considered the proposed rule's impact on efficiency, competition, and capital formation. *See* 15 U.S.C. 78c(f). The Commission believes that the proposed at-risk cross procedure is consistent with the Act in that it is intended to provide public customer orders with additional opportunity for price improvement without affording unfair advantage to the member firms that submit such customer orders and seek to trade against them. Under the proposal, a floor broker may attempt to cross a public customer order entirely against an order from the member firm from which it originated only after the floor broker, on behalf of the member firm, improves the price quoted to the customer by the trading crowd, and thereafter affords the crowd an opportunity to break up the cross by improving the price still one MPV better. Moreover, the trading crowd alternatively could break up the attempted cross by trading with the member firm's order at the member firm's price. In addition, the Commission believes that the at-risk cross procedure may encourage the members of the trading crowd to put forth their best bids or offers when the customer order is first presented to the crowd. This is because the floor broker would be able to establish priority by improving the trading crowd's quoted market, and then would be permitted to cross the entire order at the improved price. Accordingly, the Commission believes that members of the trading crowd will have a greater incentive to make larger, tighter markets in response to customer orders, thereby improving the auction market. The Commission notes further that if a public customer order either on the book or represented in the trading crowd has priority over the at-risk cross, the member firm would be permitted to participate only in those contracts remaining after the public customer's order has been filled. 11 In addition, if there is a public customer order on the book or represented in the trading crowd on the same side of the market as, and priced at or better than, the public customer order that is part of the at-risk cross, the public customer order on the book or represented in the trading crowd would have priority. 12 11 *See* Commentary .03 to Amex Rule 950-ANTE(d) and Notice, *supra* note 3, at n.7. *See also* Notice of Amendment Nos. 3 and 4, *supra* note 4. 12 *See* Notice of Amendment Nos. 3 and 4, *supra* note 4. The Commission also finds that the Exchange's at-risk cross proposal is consistent with Section 11(a) under the Act. 13 The Commission notes that orders relying on the exemption provided by Section 11(a)(1)(G) of the Act (for “G Orders”) 14 from the prohibitions of Section 11(a) may be executed as an at-risk cross only if the requirements of Section 11(a)(1)(G) are met. Specifically, the Exchange has noted that if a G Order is entered by a floor broker as part of an at-risk cross transaction, the G Order will not be permitted to execute ahead of any non-member order on the book. 15 13 15 U.S.C. 78k(a). 14 15 U.S.C. 78k(a)(1)(G). 15 *See* Notice, *supra* note 3. The Commission finds good cause for approving the proposed rule change, as amended, prior to the thirtieth day after publishing notice of Amendment Nos. 3 and 4 in the **Federal Register** . The Commission notes that the proposal, as modified by Amendment Nos. 1 and 2, was published for a full notice and comment period, 16 and that the Commission received no comment letters on the proposal. Further, Amendment Nos. 3 and 4 were published for a 15-day comment period, and the Commission received no comment letters. Amendment No. 3 made technical and clarifying changes and confirmed previous verbal representations made by the Exchange. The Commission believes that these clarifications serve to enhance the proposal and raise no new or novel issues. Amendment No. 4 proposed to permit the at-risk crossing procedure to apply to options classes that are part of the options penny pilot program (“penny pilot options”). 17 The Commission believes that orders in the penny pilot options should be afforded the same potential for price improvement through the at-risk cross procedure as other options classes, and that applying the at-risk cross procedure to penny pilot options raises no additional significant regulatory issues that were not considered in the original proposal. Therefore, the Commission believes that no purpose is served by delaying approval of the proposal, as amended. Accordingly, the Commission finds good cause, consistent with Section 19(b)(2) of the Act, 18 to approve the proposal, as modified by Amendment Nos. 1, 2, 3, and 4, on an accelerated basis. 16 *See id.* 17 *See* Securities Exchange Act Release No. 55162 (January 24, 2007), 72 FR 4738 (February 1, 2007) (SR-Amex-2006-106). Amendment No. 4 also made non-substantive rule text changes and showed the text of the final proposal as marked against the current text of Amex Rule 950-ANTE(d). 18 15 U.S.C. 78s(b)(2). IV. Conclusion *It is therefore ordered,* pursuant to Section 19(b)(2) of the Act, 19 that the proposed rule change (SR-Amex-2006-17), as modified by Amendment Nos. 1, 2, 3, and 4, be, and hereby is, approved on an accelerated basis. 19 5 U.S.C. 78s(b)(2). For the Commission, by the Division of Market Regulation, pursuant to delegated authority. 20 20 17 CFR 200.30-3(a)(12). Florence E. Harmon, Deputy Secretary. [FR Doc. E7-11367 Filed 6-12-07; 8:45 am] BILLING CODE 8010-01-P SECURITIES AND EXCHANGE COMMISSION [Release No. 34-55874; File No. SR-CBOE-2006-101] Self-Regulatory Organizations; Chicago Board Options Exchange, Incorporated; Order Approving Proposed Rule Change as Modified by Amendment Nos. 1 and 2 Thereto To Amend CBOE's Rules To Reflect the Migration of Its TPF Technology Platform Over to the Existing CBOEdirect Technology Platform June 7, 2007. I. Introduction On November 30, 2006, the Chicago Board Options Exchange, Incorporated (“CBOE” or “Exchange”) filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”) 1 and Rule 19b-4 thereunder, 2 a proposed rule change to introduce a third trading platform into its existing CBOEdirect system, “Hybrid 3.0.” The Exchange submitted Amendment No. 1 to the proposed rule change on February 15, 2007. The Exchange submitted Amendment No. 2 to the proposed rule change on April 13, 2007. 3 The proposed rule change, as modified by Amendment Nos. 1 and 2, was published for comment in the **Federal Register** on May 3, 2007. 4 The Commission did not receive any comments regarding the proposal. This order approves the proposed rule change as modified by Amendment Nos. 1 and 2. 1 15 U.S.C. 78s(b)(1). 2 17 CFR 240.19b-4. 3 Amendment No. 2 replaced and superseded Amendment No. 1 and the original filing in their entireties. 4 Securities Exchange Act Release No. 55674 (April 26, 2007), 72 FR 24639 (May 3, 2007). II. Description of the Proposal In 2003, CBOE introduced the Hybrid Trading System (“Hybrid” or “Hybrid System”), an electronic trading platform integrated with CBOE's floor-based open-outcry auction market. 5 Under CBOE's existing rules, the Hybrid System currently supports two trading platforms:
(i)The original Hybrid Trading System, which is a trading platform that allows individual Market-Makers to submit electronic quotes in their appointed classes; and
(ii)Hybrid 2.0, which is an enhanced trading platform that allows remote quoting by authorized categories of Exchange members. These two platforms operate on a technology system that is referred to as the CBOEdirect trade engine. In addition to these two platforms, prior to 2003 and through the present, CBOE has also utilized its TPF mainframe system to support trading in its “non-Hybrid” classes. 6 Therefore, options classes currently may be authorized by the Exchange to trade on the non-Hybrid, original Hybrid Trading System or Hybrid 2.0 platforms. 5 *See* Securities Exchange Act Release No. 47959 (May 30, 2003), 68 FR 34441 (June 9, 2003). 6 The three current non-Hybrid classes are options: on the S&P 100 Index—OEX; options on the S&P 500 Index—SPX; and options on the Morgan Stanley Retail Index—MVR. CBOE has determined to migrate the trading programs operating on its TPF mainframe system to the CBOEdirect trade engine. To accommodate this changeover, CBOE has proposed to amend its Hybrid rules to introduce a third trading platform into its existing CBOEdirect system, called “Hybrid 3.0,” which incorporates certain aspects of both the Hybrid Trading System and non-Hybrid platforms. The more significant aspects of the proposal are outlined below. 7 7 To incorporate Hybrid 3.0 into CBOE's existing Hybrid rules, CBOE has proposed to define all references to “Hybrid,” “Hybrid System,” and “Hybrid Trading System” in CBOE's rules to mean all CBOE hybrid platforms, including Hybrid 3.0, unless otherwise provided by a specific CBOE rule. A. Quoting As proposed, the Hybrid 3.0 platform will allow a single electronic quote, which will represent the aggregate Market Maker quoting interest in each option series for the trading crowd (“Hybrid 3.0 crowd quote”). This single quote will be generated from either an appointed Designated Primary Market Maker (“DPM”) or Lead Market Maker (“LMM”). In this way, Hybrid 3.0 will operate in a manner similar to the existing non-Hybrid platform where an appointed DPM or LMM may generate an automated quote for the trading crowd. 8 8 Currently, the non-Hybrid platform allows for the use of an Exchange-sponsored autoquote system. However, according to CBOE, this functionality will not be available for Hybrid 3.0. In Hybrid 3.0, members of the trading crowd will be able to submit manual quotes. Specifically, members of the trading crowd will be able to verbalize manual quotes to be input into Exchange systems by quote reporters for dissemination to the Options Price Reporting Authority (“OPRA”). 9 The manual quote disseminated in Hybrid 3.0 classes will be separate and additional to the Hybrid 3.0 crowd quote. If market participants (which include in-crowd market makers) are eligible to submit orders for entry into the electronic book, then the appropriate Procedure Committee may determine to disable manual quotes. 10 9 Similar to the existing functionality for manual quotes in non-Hybrid classes, in Hybrid 3.0 the Exchange's disseminated OPRA quote will not distinguish between electronic and manual quotes but members of the trading crowd will be able to distinguish between electronic and manual quotes. 10 A market participant is defined as a “Market-Maker, a Remote Market-Maker, an in-crowd DPM or LMM, an e-DPM with an appointment in the subject class, and a floor broker or PAR Official representing orders in the trading crowd.” *See* CBOE Rule 6.45B. B. Order Eligibility for Entry into Electronic Book In Hybrid 3.0, public customer orders are automatically eligible for electronic book entry. 11 Moreover, in Hybrid 3.0, the appropriate Procedure Committee can determine, on a class by class basis, to allow certain other types of orders into the electronic book, including orders of market participants and broker-dealers. 12 These eligibility rules are the same as the existing rules for other Hybrid classes except that, with respect to other Hybrid classes, market participants are eligible to submit orders for entry into the electronic book without the appropriate Procedure Committee's approval. The proposed electronic book eligibility rules for Hybrid 3.0 are consistent with current practices in CBOE's non-Hybrid classes. 13 11 *See* CBOE Rule 7.4(a)(1). 12 *Id.* 13 *See* CBOE Rule 6.8.01. C. Automatic Execution of Incoming Orders Hybrid 3.0 proposes to permit automatic execution of non-broker-dealer public customer orders. In addition, the appropriate Procedure Committee may determine, on a class by class basis, to allow orders of broker-dealers that are not market-makers or specialists on an exchange who are exempt from the provisions of Regulation T of the Federal Reserve Board pursuant to Section 7(c)(2) of the Act (“non-Market-Maker or non-Specialist broker-dealers”) to be eligible for automatic execution. 14 14 *See* proposed changes to CBOE Rule 6.13(b)(i)(C)(i). This process is consistent with the appropriate Procedure Committee's ability to permit broker-dealer orders to be automatically executed through the Exchange's Retail Automatic Execution System (“RAES”) in CBOE's non-Hybrid Classes. *See* CBOE Rule 6.8.01. For Hybrid 3.0 classes, incoming orders that are eligible to receive automatic execution will execute against public customer orders in the electronic book. The remaining balance of the incoming order, if any, may be
(i)Represented in the electronic book provided such order is eligible for book entry 15 or
(ii)if the order is not eligible for book entry, it will route to PAR, BART, or to the order entry firm's booth printer. 15 Even if an order is eligible for book entry, the order entry firm will have the discretion to have the remaining balance of the eligible order route to PAR, BART, or to the order entry firm's booth printer. On the Hybrid 3.0 platform, automatic execution against quotes (whether electronic or manual) will not be allowed. 16 However, if the electronic book price matches a manual quote, then automatic execution will be permissible against public customer orders in the electronic book. 17 CBOE represented that, consistent with existing practices in CBOE's non-Hybrid Classes, the Exchange will apply similar firm quote surveillance procedures in Hybrid 3.0 to monitor for compliance with members' firm quote obligations. 16 *See* CBOE Rule 6.13. By comparison, currently in CBOE's non-Hybrid Classes, orders may be eligible for automatic execution against market maker quotes on RAES. *See* CBOE Rules 6.8 and 24.17. The Exchange represents that the number of trades that occur on RAES is minimal (approximately 1/10th of 1% of all volume occurs on RAES). 17 *See* proposed changes to CBOE Rule 6.43(b). For example, if the electronic book is a $1.20 bid and the manual quote is at a $1.20 bid, then the system will allow for automatic execution against the $1.20 electronic book bid but not the $1.20 quote. In addition, if the Hybrid 3.0 crowd quote matches the electronic book price, automatic execution against public customer orders in the book is permissible. D. Application of CBOE Rule 6.45B CBOE Rule 6.45B, which relates to the priority and allocation of trades, will apply to trading in Hybrid 3.0 classes in the same way it is applied to CBOE's existing Hybrid Trading System. For example, multiple customer orders in the electronic book at the same price will be ranked based on time priority pursuant to the priority methods set forth in Rule 6.45B. 18 Further, unlike CBOE's non-Hybrid classes, Hybrid 3.0 will allow
(i)Each Market-Maker in the trading crowd and
(ii)all floor brokers in the trading crowd (collectively referred to as “in-crowd market participants” or “ICMPs”) to trade against the electronic book pursuant to CBOE Rule 6.45B(c). 19 18 *See* CBOE Rule 6.45B(a)(ii)(A)(1). 19 This process is the same as for existing Hybrid classes. CBOE Rule 6.45B(d) currently governs the interaction of quotes when they are locked ( *e.g.* , $1.00 bid—1.00 offer). Specifically, CBOE Rule 6.45B(d) provides that when the quotes of two Market-Makers interact ( *i.e.* , “quote lock”), either party has one second during which it may move its quote without obligation to trade with the other party. If, however, the quotes remain locked at the conclusion of one-second, the quotes trade in full against each other. For quote locks in Hybrid 3.0 classes, the appropriate Procedure Committee will set the length of the counting period, provided that the period shall not exceed ten seconds. 20 According to the Exchange, the proposed ten second threshold is intended to provide additional flexibility for Market-Makers to become acclimated with Hybrid 3.0. 21 20 *See* proposed changes to CBOE Rule 6.45B(d). 21 By comparison, the current quote lock timer for Hybrid and Hybrid 2.0 classes may not exceed one second. *See* CBOE Rule 6.45B(d)(i)(C). Regarding the time periods required for order exposure in Interpretation .01 of Rule 6.45B (“Principal Transactions”) and Interpretation .02 of Rule 6.45B (“Solicitation Orders”), CBOE has proposed a minimum exposure time for Hybrid 3.0 classes, on a class by class basis, to be at least three seconds but not to exceed thirty seconds. 22 According to CBOE, this extended time frame for exposure will provide additional flexibility as ICMPs become more acclimated with Hybrid 3.0. 23 22 *See* proposed changes to CBOE Rule 6.45B.01 and 6.45B.02. 23 By comparison, the current exposure period for Hybrid and Hybrid 2.0 classes is at least three seconds. *See* CBOE Rule 6.45B.01 and 6.45B.02. E. Opening Procedures Only the DPM or LMM responsible for generating the Hybrid 3.0 crowd quote will be required to enter quotes as part of the opening rotations in Hybrid 3.0 option classes. The DPM or LMM must enter opening quotes in opening rotations that comply with the legal quote width requirements of Rule 8.7(b)(iv), and if there is not a quote present in a series that complies with the legal quote width requirements of Rule 8.7(b)(iv), then that series will not open. 24 Additionally, Hybrid 3.0 will allow public customer, broker-dealer, Exchange Market-Maker, away Marker-Maker and Specialist participation in the opening. Since Hybrid 3.0 is a single quoter environment, these participants will not be permitted to enter opening quotes in opening rotations but will be permitted to directly enter opening orders in opening rotations in Hybrid 3.0 classes. 25 Further, similar to the rules for CBOE's non-Hybrid classes, Hybrid 3.0 also proposes to allow special “modified” opening procedures for settlement in options on the Volatility Indexes. 26 24 This is consistent with the opening quote requirements in CBOE's existing Hybrid classes that utilize CBOE's Hybrid Opening System (“HOSS”). *See* CBOE Rule 6.2B. 25 *See* proposed Interpretation .01 to CBOE Rule 6.2B. By comparison, currently in non-Hybrid option classes (such as SPX and OEX), public customers, Market-Makers and broker-dealers are not able to directly participate in the opening rotations (for series that utilize the Exhange's Rapid Opening System). For example, Market-Makers who wish to participate on ROS in the opening rotation in non-Hybrid option classes must submit orders through the LMM at least ten minutes prior to the opening of trading pursuant to CBOE Rules 6.2A and 24.13. 26 *See* the “Modified HOSS Opening Procedures” in proposed Interpretation .01 to CBOE Rule 6.2B. By comparison, non-Hybrid option classes that utilize RAES and ROS have special procedures for purposes of settlement in the volatility indexes called “Modified ROS Opening Procedures” pursuant to Interpretation .03 to CBOE Rule 6.2A. III. Discussion The Commission has reviewed carefully the proposed rule change, as amended, and finds that it is consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange. 27 In particular, the Commission finds that the proposed rule change is consistent with Section 6(b)(5) of the Act, 28 which requires that an exchange have rules designed, among other things, to promote just and equitable principles of trade, to remove impediments to and perfect the mechanism of a free and open market and a national market system, and in general to protect investors and the public interest. The proposed rules for Hybrid 3.0 are similar to existing rules applicable to trading in Hybrid and/or non-Hybrid classes. The Commission believes that the proposed rules for the Hybrid 3.0 platform, including those pertaining to quoting, order eligibility in the electronic book, automatic execution, order priority and allocation, are consistent with the Act. 27 In approving this proposal, the Commission has considered the proposed rule's impact on efficiency, competition, and capital formation. 15 U.S.C. 78c(f). 28 15 U.S.C. 78f(b)(5). *It is therefore ordered,* pursuant to Section 19(b)(2) of the Act, 29 that the proposed rule change as modified by Amendment Nos. 1 and 2 thereto (File No. SR-CBOE-2006-101) be, and hereby is, approved. 29 15 U.S.C. 78s(b)(2). For the Commission, by the Division of Market Regulation, pursuant delegated authority. 30 30 17 CFR 200.30-3(a)(12). Florence E. Harmon, Deputy Secretary. [FR Doc. E7-11366 Filed 6-12-07; 8:45 am] BILLING CODE 8010-01-P SECURITIES AND EXCHANGE COMMISSION [Release No. 34-55873; File No. SR-CBOE-2007-50] Self-Regulatory Organizations; Chicago Board Options Exchange, Incorporated; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change Relating to Its Marketing Fee Program June 7, 2007. Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”) 1 and Rule 19b-4 thereunder, 2 notice is hereby given that on May 29, 2007, the Chicago Board Options Exchange, Incorporated (“CBOE” or “Exchange”) filed with the Securities and Exchange Commission (“Commission”) the proposed rule change as described in Items I, II, and III below, which Items have been substantially prepared by the Exchange. CBOE has designated this proposal as one establishing or changing a due, fee, or other charge imposed by CBOE under Section 19(b)(3)(A)(ii) of the Act 3 and Rule 19b-4(f)(2) thereunder, 4 which renders the proposal effective upon filing with the Commission. The Commission is publishing this notice to solicit comments on the proposed rule change from interested persons. 1 15 U.S.C. 78s(b)(1). 2 17 CFR 240.19b-4. 3 15 U.S.C. 78s(b)(3)(A)(ii). 4 17 CFR 240.19b-4(f)(2). I. Self-Regulatory Organization's Statement of the Terms of Substance of the Proposed Rule Change CBOE proposes to amend its Marketing Fee Program. The text of the proposed rule change is available at the Exchange, the Commission's Public Reference Room, and *http://www.cboe.com.* II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change, and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. CBOE has substantially prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements. A. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change 1. Purpose CBOE proposes to amend its marketing fee program in two respects. First, CBOE proposes to amend its fees schedule to reduce the fee that is collected in the option classes participating in the Penny Pilot Program in which the marketing fee is applicable from $0.25 to $0.10. CBOE intends to implement this change effective June 1, 2007. Second, CBOE's marketing fee program states that it is currently in effect until June 2, 2007, which is the date that CBOE's pilot program establishing its Preferred Market-Maker Program is scheduled to expire. However, CBOE has filed a proposed rule change requesting permanent approval of its Preferred Market-Maker Program. 5 Therefore, CBOE proposes to delete the last sentence in footnote 6 of its fees schedule that states, “CBOE's marketing fee program as described above will be in effect until June 2, 2007.” 5 *See* Securities Exchange Act Release No. 55826 (May 29, 2007), 72 FR 31357 (SR-CBOE-2007-47) (permanent approval of CBOE's Preferred Market-Maker Program). CBOE is not amending its marketing fee program in any other respects. 2. Statutory Basis The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Act 6 in general, and Section 6(b)(4) of the Act 7 in particular, in that it is designed to provide for the equitable allocation of reasonable dues, fees, and other charges among CBOE members and other persons using its facilities. 6 15 U.S.C. 78f(b). 7 15 U.S.C. 78f(b)(4). B. Self-Regulatory Organization's Statement on Burden on Competition The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. C. Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants, or Others No written comments were solicited or received with respect to the proposed rule change. III. Date of Effectiveness of the Proposed Rule Change and Timing for Commission Action The foregoing proposed rule change has been designated as a fee change pursuant to Section 19(b)(3)(A)(ii) of the Act 8 and Rule 19b-4(f)(2) 9 thereunder, because it establishes or changes a due, fee, or other charge imposed by the Exchange. Accordingly, the proposal will take effect upon filing with the Commission. At any time within 60 days of the filing of such proposed rule change the Commission may summarily abrogate such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. 8 15 U.S.C. 78s(b)(3)(A)(ii). 9 17 CFR 240.19b-4(f)(2). IV. Solicitation of Comments Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods: Electronic Comments • Use the Commission's Internet comment form ( *http://www.sec.gov/rules/sro.shtml* ); or • Send an e-mail to *rule-comments@sec.gov.* Please include File Number SR-CBOE-2007-50 on the subject line. Paper Comments • Send paper comments in triplicate to Nancy M. Morris, Secretary, Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-1090. All submissions should refer to File Number SR-CBOE-2007-50. This file number should be included on the subject line if e-mail is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site ( *http://www.sec.gov/rules/sro.shtml* ). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for inspection and copying in the Commission's Public Reference Room. Copies of such filing also will be available for inspection and copying at the principal office of CBOE. All comments received will be posted without change; the Commission does not edit personal identifying information from submissions. You should submit only information that you wish to make available publicly. All submissions should refer to File Number SR-CBOE-2007-50 and should be submitted on or before July 5, 2007. For the Commission, by the Division of Market Regulation, pursuant to delegated authority. 10 10 17 CFR 200.30-3(a)(12). Florence E. Harmon, Deputy Secretary. [FR Doc. E7-11371 Filed 6-12-07; 8:45 am] BILLING CODE 8010-01-P SECURITIES AND EXCHANGE COMMISSION [Release No. 34-55870; File No. SR-NASDAQ-2007-037] Self-Regulatory Organizations; The NASDAQ Stock Market LLC; Notice of Filing of Proposed Rule Change To Modify Order Audit Trail System Rules To Provide an Exemption From Transmission Requirements for Proprietary Orders and Amendment No. 1 Thereto June 6, 2007. Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”), 1 and Rule 19b-4 thereunder, 2 notice is hereby given that on April 3, 2007, The NASDAQ Stock Market LLC (“Nasdaq”) filed with the Securities and Exchange Commission (“Commission”) the proposed rule change as described in Items I, II, and III below, which Items have been substantially prepared by Nasdaq. On June 4, 2007, Nasdaq filed Amendment No. 1, which replaced the text of the original filing in its entirety. The Commission is publishing this notice to solicit comments on the proposed rule change, as amended, from interested persons. 1 15 U.S.C. 78s(b)(1). 2 17 CFR 240.19b-4. I. Self-Regulatory Organization's Statement of the Terms of the Substance of the Proposed Rule Change Nasdaq proposes to modify its Order Audit Trail System (“OATS”) rules to provide an exemption from OATS transmission requirements for certain proprietary orders. The text of the proposed rule change is available at *http://www.nasdaq.com* , at Nasdaq, and at the Commission's Public Reference Room. II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change In its filing with the Commission, Nasdaq included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. Nasdaq has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements. A. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change 1. Purpose Nasdaq proposes to modify its OATS rules to adopt a limited exemption from OATS order data transmission requirements for proprietary trading firms. OATS is an integrated audit trail of order, quote, and trade information for Nasdaq securities used to recreate events in the life cycle of orders and more completely monitor the trading practices of member firms. A “Proprietary Trading Firm” is proposed to be defined as meaning a Nasdaq member that trades its own capital with all the trading being done in the firm's accounts by traders that are owners of, employees of, or contractors to the firm. Additionally, a Proprietary Trading Firm does not have “customers,” as that term is defined in Nasdaq Rule 0120(g) and is not a member of the National Association of Securities Dealers, Inc. (“NASD”). At present, there are no Proprietary Trading Firms that are also market makers. Nasdaq also proposes to revise Nasdaq Rule 6955 to add that a Proprietary Trading Firm, and persons associated with a Proprietary Trading Firm, only upon request would be required to transmit order data information for specific time periods stated in a request to Nasdaq Regulation. 3 Although a Proprietary Trading Firm would not be required to transmit the order data information to Nasdaq Regulation unless requested, it still would be held responsible for maintaining and retaining the information in a format that could be easily integrated into the NASD's OATS system in the event Nasdaq Regulation makes a request for such information. 3 Rule 0130 provides that the term Nasdaq Regulation should be understood as also referring to NASD staff, NASD Regulation staff, and NASD departments acting on behalf of Nasdaq pursuant to the Regulatory Contract. NASD Regulation has agreed to perform certain functions on behalf of Nasdaq pursuant to a regulatory services agreement. The current requirement for Proprietary Trading Firms to transmit all data order information is onerous and not offset by an equivalent regulatory benefit. It is very expensive for firms to develop and maintain the compliance systems and compliance staff required to continuously monitor the daily transmission of OATS data. Additionally, the transmission of OATS data often results in either rejections or mismatches. 4 4 OATS rejections may occur for a multitude of reasons including: Incorrect symbol; duplicate order event; cancelled time stamp prior to order timestamp; canceled timestamp greater than current date and time; issue is not reportable to OATS; issue symbol invalid for order event date; missing or invalid shares quantity or Buy/Sell code; missing or invalid member type code or issue symbol ID; missing or invalid cancel quantity; missing time in force code; missing or invalid firm order ID; and missing or invalid expiration time. Errors can result from a programming error even if it just a misplaced semicolon. To cure these issues, members may need to spend an inordinate amount of time correcting a minor glitch with NASD. Mismatches occur when NASD reconstitutes the order and any discrepancies exist between the order origination and order execution, which may be different entities. 5 Often times the discrepancy is of very minor consequence, but triage efforts are overly burdensome. 5 Common causes of mismatches include: missing branch/sequence numbers; improperly formatted branch/sequence numbers on one of the reports; differing execution timestamps; missing reporting exception codes and late reporting of OATS execution reports. The basis for OATS is customer protection through the transparency of the executions of customer orders. The proposed rule change does not impact this, since by definition, Proprietary Trading Firms do not handle customer orders. OATS was designed to provide an accurate, time-sequenced record of orders and transactions, beginning with the receipt of an order at the first point of contact between the broker-dealer and the customer or counterparty and further documenting the life of the order through the process of execution. This requirement only came into effect during the later stages of the OATS implementation. Also, as mentioned below, no other exchange has a daily transmission requirement for this category of customer. This approach parallels, in a much more limited manner, the approach undertaken by the New York Stock Exchange (“NYSE”) in NYSE Rule 132C, which requires NYSE members, upon request, to transmit order tracking data to the NYSE. 6 The NYSE has stated that it has been its experience that “submission of data by request has proven to be effective and efficient” 7 from both the NYSE's and its members' perspective. 6 *See* Securities Exchange Act Release No. 47689 (April 17, 2003), 68 FR 20200 (April 24, 2003) (SR-NYSE-99-51). 7 *Id* . at 20202. Additionally, much of the information retained by a Proprietary Trading Firm is otherwise available to the Nasdaq Regulation through Nasdaq's systems, and Nasdaq can use such information and supply it to the NASD, upon request, as well. This information includes trade reporting data, including order time and sales data captured by the Nasdaq system. 2. Statutory Basis Nasdaq believes that the proposed rule change is consistent with the provisions of Section 6 of the Act, 8 in general, and with Section 6(b)(5) of the Act, 9 in particular, in that the proposal is designed to prevent fraudulent and manipulative acts and practices, to promote just and equitable principles of trade, to foster cooperation and coordination with persons engaged in regulating, clearing, settling, processing information with respect to, and facilitating transactions in securities, to remove impediments to and perfect the mechanism of a free and open market and a national market system, and, in general, to protect investors and the public interest. 8 15 U.S.C. 78f. 9 15 U.S.C. 78f(b)(5). B. Self-Regulatory Organization's Statement on Burden on Competition Nasdaq does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act, as amended. C. Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants, or Others Written comments were neither solicited nor received. III. Date of Effectiveness of the Proposed Rule Change and Timing for Commission Action Within 35 days of the date of publication of this notice in the **Federal Register** or within such longer period
(i)as the Commission may designate up to 90 days of such date if it finds such longer period to be appropriate and publishes its reasons for so finding or
(ii)as to which the self-regulatory organization consents, the Commission will: A. By order approve such proposed rule change, or B. Institute proceedings to determine whether the proposed rule change should be disapproved. IV. Solicitation of Comments Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change, as amended, is consistent with the Act. Comments may be submitted by any of the following methods: Electronic Comments • Use the Commission's Internet comment form ( *http://www.sec.gov/rules/sro.shtml* ); or • Send an e-mail to *rule-comments@sec.gov* . Please include File Number SR-NASDAQ-2007-037 on the subject line. Paper Comments • Send paper comments in triplicate to Nancy M. Morris, Secretary, Securities and Exchange Commission, Station Place, 100 F Street, NE., Washington, DC 20549-9303. All submissions should refer to File Number SR-NASDAQ-2007-037. This file number should be included on the subject line if e-mail is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site ( *http://www.sec.gov/rules/sro.shtml* ). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for inspection and copying in the Commission's Public Reference Room. Copies of such filing also will be available for inspection and copying at the principal office of the Nasdaq. All comments received will be posted without change; the Commission does not edit personal identifying information from submissions. You should submit only information that you wish to make available publicly. All submissions should refer to File Number SR-NASDAQ-2007-037 and should be submitted on or before July 5, 2007. For the Commission, by the Division of Market Regulation, pursuant to delegated authority. 10 Florence E. Harmon, Deputy Secretary. 10 17 CFR 200.30-3(a)(12). [FR Doc. E7-11369 Filed 6-12-07; 8:45 am] BILLING CODE 8010-01-P SECURITIES AND EXCHANGE COMMISSION [Release No. 34-55872; File No. SR-OCC-2007-01] Self-Regulatory Organizations; The Options Clearing Corporation; Order Granting Approval of a Proposed Rule Change Relating to Credit Default Options June 6, 2007. I. Introduction On February 13, 2007, The Options Clearing Corporation (“OCC”) filed with the Securities and Exchange Commission (“Commission”) proposed rule change File No. SR-OCC-2007-01 pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”). 1 On March 7, 2007, OCC filed an amendment to the proposed rule change. 2 Notice of the proposal was published in the **Federal Register** on March 5, 2007. 3 No comment letters were received. This order approves the proposed rule change as amended. 1 15 U.S.C. 78s(b)(1). 2 The March 7, 2007, amendment reflects OCC's determination to seek approval for the credit default option product only and not for binary options in general. Because Amendment No. 1 is technical in nature, the Commission is not republishing the notice of filing for public comment. 3 Securities Exchange Act Release No. 55362 (February 27, 2007), 72 FR 9826. II. Description The purpose of the proposed rule change is to permit OCC to clear and settle credit default options (“CDOs”), which are options related to the creditworthiness of an issuer or guarantor (“reference entity”) of one or more specified debt securities (“reference obligation(s)”). CDOs are “binary” options that pay a fixed amount to the holder of the option upon the occurrence of a “credit event” affecting the reference obligations. 4 CDOs will be traded by the Chicago Board Options Exchange (“CBOE”). 5 4 “Binary” options (also sometimes referred to as “ digital” options) are “all-or-nothing” options that pay a fixed amount if automatically exercised and otherwise pay nothing. 5 Securities Exchange Act Release Nos. 55251 (February 7, 2007), 72 FR 7091 (February 14, 2007) (notice of filing of proposed rule change); 55871 (June 6, 2007) (order approving proposed rule change) [File No. SR-CBOE-2006-84]. Description of Credit Default Options CDOs are structured as binary options that are automatically exercised and the exercise settlement amount payable if a “credit event” occurs at any time prior to the last day of trading. A “credit event” is generally defined as any failure to pay on any of the reference obligations or any other occurrence that would constitute an “event of default” or “restructuring” under the terms of any of the reference obligations and that the listing exchange has determined would be a credit event for purposes of the CDO. The payout or settlement amount for a single exercised option CBOE CDO will be $100,000. By-Law and Rule Amendments Applicable to CDOs In order to accommodate trading in CDOs, OCC is adding a new By-Law Article and a new Chapter to its Rules to incorporate several new defined terms and procedures for clearing and settling CDOs. 1. Terminology—Article I, Section 1 and Article XIV, Section 1 of the By-Laws The definition of “expiration time” in Article I of the By-Laws is modified to be a default provision to permit the expiration time to be defined differently for different classes of options. The definition of “option contract” in Article I of the By-Laws is amended to include a credit default option and to provide a more generic definition of “cash-settled option.” “Adjustment event” is defined in Article XIV by reference to the rules of the listing exchange. Similarly, “credit event” is defined by reference to exchange rules. The terms “credit event confirmation” and “credit event confirmation deadline” are used, respectively, to refer to the notice that must be provided by the listing exchange or other reporting authority to OCC that a credit event has occurred (and that a CDO will therefore automatically be exercised) and to the deadline for receipt of such notice if it is to be treated as having been received on the business day on which it is submitted. Credit event confirmations received after the deadline on the expiration date but before the expiration time will be given effect but may result in delayed exercise settlement. OCC is also defining the term “exercise settlement amount” in Article XIV for purposes of credit default options. The exercise settlement amount of a credit default option is the amount specified by the exchange on which the option is traded that will be paid in settlement of an automatically exercised option. CBOE has specified the exercise settlement amount for a single CDO as $100,000. OCC's proposed definition would permit an exchange to specify a different exercise settlement amount. The exercise settlement amount will be determined by the exchange at the time of listing when the exchange fixes the other variable terms for the options of a particular class or series. OCC is replacing the definitions of “variable terms,” “premium,” and “multiplier” in Article I with revised definitions in Article XIV, Section 1 that are applicable to credit default options. The term “class” is also redefined in Article XIV, Section 1. To be within the same class, CDOs must have the same reporting authority, which OCC anticipates will ordinarily be the listing exchange. This is necessary because of the degree of discretion that the reporting authority will have in determining whether a credit event has occurred. CDOs will be a category of options where exercise is triggered by a discrete event such as a “credit event” affecting the “reference obligations” issued by a “reference entity,” which terms are defined to have the meanings given to them in the rules of the listing exchange. The term “underlying interest” is defined to be the reference obligation(s) with respect to which the credit event will or will not occur. 2. Terms of Cleared Contracts—Article VI, Section 10(e) A new paragraph
(e)is added to Article VI, Section 10 so that an exchange is required to designate the exercise settlement amount, expiration date, and exercise price for a series of credit default options at the time the series is opened for trading. Section 10(e) also reminds the reader that credit default options are subject to adjustment under Article XIV. 3. Rights and Obligations—Article XIV, Section 2 Article XIV, Section 2 defines the general rights and obligations of holders and writers of credit default options. As noted above, the holder of a credit default option that is automatically exercised has the right to receive the fixed exercise settlement amount from OCC, and the assigned writer has the obligation to pay that amount to OCC. 4. Adjustments of Credit Default Options—Article XIV, Section 3; Determination of Occurrence of Credit Event—Article XIV, Section 4 Article XIV, Section 3 provides for adjustment of CDOs in accordance with the rules of the listing exchange. CBOE's rules provide for adjustment of CDOs in the case of certain corporate events affecting the reference obligations, and OCC proposes simply to defer to the rules and to the determinations of the listing exchange pursuant to its rules. Accordingly, OCC will have no responsibility for adjustment determinations with respect to CDOs. Similarly, Section 4 provides that the listing exchange for a class of CDOs will have responsibility for determining the occurrence of a credit event that will result in automatic exercise of the options of that class. The listing exchange has the obligation to provide a credit event confirmation to OCC in order to trigger the automatic exercise. 5. Exercise and Settlement—Chapter XV of the Rules and Rule 801 Credit default options will not be subject to the exercise-by-exception procedures applicable to most other options under OCC's Rules but would instead be automatically exercised at expiration if the specified criterion for exercise is met. The procedures for the automatic exercise of credit default options, as well as their assignment and settlement (including during periods when a clearing member is suspended), are set forth in Rules 1501 through 1505 of new Chapter XV and in revised Rule 801(b). 6. Special Margin Requirements—Rule 601; Deposits in Lieu of Margin—Rule 1506 OCC will not initially margin CDOs through its usual “STANS” system. Because of CDOs' fixed payout feature, further systems development is needed to accommodate these options in STANS. Until such development is completed, OCC has initially determined to require that writers of such options post margin in a fixed amount that will be set at 100% of the fixed exercise settlement amount applicable to each series of CDOs. OCC would have discretion to reduce the requirement to something less than 100% if research, analysis, and experience suggest that a lower percentage is sufficient. Initially, long positions in CDOs will be valued at zero and will provide no offset against margin requirements on shorts. Again, based on research, analysis, and experience, OCC may determine to give some value to the longs. Ultimately, CDOs will be incorporated into the STANS system and will be valued and margined on a risk basis. OCC does not propose to accept escrow deposits in lieu of clearing margin for credit default options. Therefore, Rule 1506 states that Rule 610, which otherwise would permit such deposits, does not apply to credit default options. 7. Acceleration of Expiration Date—Rule 1507 This provision permits OCC to accelerate the expiration date of a credit default option when the option is deemed to have been exercised on any day prior to the expiration date. III. Discussion Section 17A(b)(3)(F) of the Act requires that the rules of a clearing agency be designed to promote the prompt and accurate clearance and settlement of securities transactions. 6 The Commission finds the proposed rule change to be consistent with Section 17A(b)(3)(F) of the Act because it is designed to promote the prompt and accurate clearance and settlement of transactions in, including exercises of, credit default options and to remove impediments to and perfect the mechanism of a national system for the prompt and accurate clearance and settlement of such transactions. 7 These purposes are accomplished by having the clearance and settlement of CDOs take place at OCC and by OCC applying substantially the same rules and procedures to CDOs as it applies to similar transactions in other cash-settled options. 6 15 U.S.C. 78q-1(b)(3)(F). 7 In approving this proposed rule change, the Commission has considered the proposed rule's impact on efficiency, competition, and capital formation. *See* 15 U.S.C. 78c(f). IV. Conclusion On the basis of the foregoing, the Commission finds that the proposed rule change is consistent with the requirements of the Act and in particular Section 17A of the Act and the rules and regulations thereunder. *It is therefore ordered,* pursuant to Section 19(b)(2) of the Act, that the proposed rule change (File No. SR-OCC-2007-01) as modified by Amendment No. 1 be and hereby is approved. For the Commission by the Division of Market Regulation, pursuant to delegated authority. 8 8 17 CFR 200.30-3(a)(12). Florence E. Harmon, Deputy Secretary. [FR Doc. E7-11370 Filed 6-12-07; 8:45 am] BILLING CODE 8010-01-P SECURITIES AND EXCHANGE COMMISSION [Release No. 34-55860; File No. SR-Phlx-2007-41] Self-Regulatory Organizations; Philadelphia Stock Exchange, Inc.; Notice of Filing and Immediate Effectiveness of Proposed Rule Change Relating to the Modification of Phlx Rule 185A June 5, 2007. Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”), 1 and Rule 19b-4 2 thereunder, notice is hereby given that on May 25, 2007, the Philadelphia Stock Exchange, Inc. (“Phlx” or “Exchange”) filed with the Securities and Exchange Commission (“Commission”) the proposed rule change as described in Items I and II, below, which Items have been prepared by the Phlx. The Exchange filed the proposal as a “non-controversial” rule change pursuant to Section 19(b)(3)(A) of the Act 3 and Rule 19b-4(f)(6) thereunder, 4 which rendered the proposal effective upon filing with the Commission. The Commission is publishing this notice to solicit comments on the proposed rule change from interested persons. 1 15 U.S.C. 78s(b)(1). 2 17 CFR 240.19b-4. 3 15 U.S.C. 78s(b)(3)(A). 4 17 CFR 240.19b-4(f)(6). I. Self-Regulatory Organization's Statement of the Terms of Substance of the Proposed Rule Change The Phlx proposes to amend Phlx Rule 185A, which clarified the entry, routing and other requirements of certain orders on XLE, the Exchange's electronic equity trading system, prior to March 5, 2007, the Trading Phase Date, 5 to make certain provisions of the rule applicable until the All Stocks Phase Date. 6 The text of the proposed rule change is available on Phlx's Web site, *http://www.phlx.com* , at Phlx's principal office, and at the Commission's Public Reference Room. 5 The Trading Phase Date was the “[f]inal date for full operation of Regulation NMS-compliant trading systems [by exchanges] that intend[ed] to qualify their quotations for trade-through protection under Rule 611 [during the roll-out of Regulation NMS].” *See* Securities Exchange Act Release No. 55160 (January 24, 2007), 72 FR 4202 (January 30, 2007). 6 The All Stocks Phase Date is the date that full industry compliance with Rules 610 and 611 of Regulation NMS, 17 CFR 242.610 and 611, begins. Currently, the All Stocks Phase Date is scheduled to be August 20, 2007. *See* Securities Exchange Act Release No. 55160 (January 24, 2007), 72 FR 4202 (January 30, 2007). However, should the Commission change the All Stocks Phase Date, the changes to Phlx Rule 185A adopted in this proposed rule change will remain in effect until that new date. II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change In its filing with the Commission, the Phlx included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Phlx has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements. A. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change 1. Purpose The purpose of the proposed rule change is to clarify the obligation of XLE Participants when submitting certain XLE order types before the All Stocks Phase Date. Phlx Rule 185A, Orders and Order Execution—Temporary, was adopted in November 2006, to clarify the entry, routing and other requirements of certain orders on XLE in the period before the Trading Phase Date. 7 Phlx Rule 185A was subsequently amended twice. 8 Each amendment addressed the period before the Trading Phase Date. 7 *See* Securities Exchange Act Release No. 54760 (November 15, 2006), 71 FR 67687 (November 22, 2006) (SR-Phlx-2006-76). 8 *See* Securities Exchange Act Release Nos. 55044 (January 5, 2007), 72 FR 1361 (January 11, 2007) (SR-Phlx-2006-92) and 54788 (November 20, 2006), 71 FR 68877 (November 28, 2006) (SR-Phlx-2006-77). Phlx Rule 185A clarified the routing of orders from XLE to other marketplaces, 9 the entry of Intermarket Sweep Orders and IOC Cross Orders marked by the XLE Participant entering the order as meeting the requirement of an intermarket sweep order, 10 the requirements for certain IOC Cross Orders marked as Benchmark, 11 and the requirements for certain IOC Cross Orders marked as Qualified Continent Trades. 12 At this time, Phlx proposes to delete the provisions of Phlx Rule 185A that applied to routing and modify the remaining provisions of the rule to make them applicable to the period prior to the All Stocks Phase Date. 9 *See* Phlx Rule 185A(a). 10 *See* Phlx Rule 185A(b). 11 *See* Phlx Rule 185A(c). 12 *See* Phlx Rule 185A(d). Specifically Phlx Rule 185A(a) is being modified to delete provisions regarding routing of orders on XLE since intermarket sweep orders have been available at all venues to which XLE will route an order since the Trading Phase Date. In its place, Phlx Rule 185A(a) will define the term “All Stocks Phase Date.” Additionally, Phlx Rule 185A(b)-(d) are being amended to substitute the term “All Stocks Phase Date” for “Trading Phase Date” as the provisions of these sections of the rule will apply until the All Stocks Phase Date. At that time, Phlx will delete Phlx Rule 185A from its rulebook as it will no longer have any effect. 2. Statutory Basis The Exchange believes that its proposal is consistent with Section 6(b) of the Act 13 in general, and furthers the objectives of Section 6(b)(5) of the Act 14 in particular, in that it is designed to promote just and equitable principles of trade, to remove impediments to and perfect the mechanism of a free and open market and a national market system, and, in general to protect investors and the public interest. 13 15 U.S.C. 78f(b). 14 15 U.S.C. 78f(b)(5). B. Self-Regulatory Organization's Statement on Burden on Competition The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. C. Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants, or Others No written comments were either solicited or received. III. Date of Effectiveness of the Proposed Rule Change and Timing for Commission Action Because the foregoing rule
(i)does not significantly affect the protection of investors or the public interest;
(ii)does not impose any significant burden on competition; and
(iii)by its terms, does not become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate if consistent with the protection of investors and the public interest, provided that the Exchange has given the Commission written notice of its intent to file the proposed rule change at least five business days prior to the date of filing of the proposed rule change or such shorter time as designated by the Commission, the proposed rule change has become effective pursuant to Section 19(b)(3)(A) of the Act 15 and Rule 19b-4(f)(6) thereunder. 16 As required under Rule 19b-4(f)(6)(iii) under the Act, 17 Phlx provided the Commission with written notice of its intent to file the proposed rule change, along with a brief description and text of the proposed rule change, prior to the date of the filing of the proposed rule change. 15 15 U.S.C. 78s(b)(3)(A). 16 17 CFR 240.19b-4(f)(6). 17 17 CFR 240.19b-4(f)(6)(iii). A proposed rule change filed under Rule 19b-4(f)(6) under the Act 18 normally may not become operative prior to 30 days after the date of filing. However, Rule 19b-4(f)(6)(iii) under the Act 19 permits the Commission to designate a shorter time if such action is consistent with the protection of investors and the public interest. The Exchange has requested that the Commission waive the 30-day operative delay, which would make the rule change effective and operative upon filing. In its filing, the Exchange stated its belief that waiver of the operative delay would be consistent with the protection of investors and the public interest because the amended temporary rule should eliminate potential confusion relating to orders on XLE and clarify XLE Participant obligations when submitting certain order types to the Exchange. 18 17 CFR 240.19b-4(f)(6). 19 17 CFR 240.19b-4(f)(6)(iii). The Commission believes that waiver of the 30-day operative delay is consistent with the protection of investors and the public interest because the proposed rule change clarifies the obligations of XLE Participants when submitting certain order types to the Exchange before the All Stocks Phase Date. In particular, the proposal amends the text of Phlx Rule 185A, which had previously been applicable to the Trading Phase Date, to reflect the applicability of those provisions which will remain in effect until the All Stocks Phase Date. Once the All Stocks Phase Date arrives, the applicable provisions of Phlx Rule 185 will be operative and the Exchange will no longer need temporary Rule 185A. 20 Accordingly, consistent with the protection of investors and the public interest, the Commission designates the proposed rule change to be operative upon filing with the Commission. 21 20 As the Exchange has made clear in its filing, it intends to delete Phlx Rule 185A from its rulebook upon the All Stocks Phase Date. Given the definitively limited application of the amended rule and the specified removal date, the Exchange does not intend to file a separate proposed rule change to remove the rule text from its rulebook, but rather will remove the rule as specified. 21 For the purposes only of waiving the 30-day operative delay, the Commission has considered the proposed rule's impact on efficiency, competition, and capital formation. *See* 15 U.S.C. 78c(f). At any time within 60 days of the filing of the proposed rule change the Commission may summarily abrogate such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. 22 22 *See* 15 U.S.C. 78s(b)(3)(C). IV. Solicitation of Comments Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods: Electronic Comments • Use the Commission's Internet comment form ( *http://www.sec.gov/rules/sro.shtml* ); or • Send an e-mail to *rule-comments@sec.gov* . Please include File Number SR-Phlx-2007-41 on the subject line. Paper Comments • Send paper comments in triplicate to Nancy M. Morris, Secretary, Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-1090. All submissions should refer to File Number SR-Phlx-2007-41. This file number should be included on the subject line if e-mail is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site ( *http://www.sec.gov/rules/sro.shtml* ). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for inspection and copying in the Commission's Public Reference Room. Copies of the filing also will be available for inspection and copying at the principal office of the Phlx. All comments received will be posted without change; the Commission does not edit personal identifying information from submissions. You should submit only information that you wish to make available publicly. All submissions should refer to File Number SR-Phlx-2007-41 and should be submitted on or before July 5, 2007. For the Commission, by the Division of Market Regulation, pursuant to delegated authority. 23 23 17 CFR 200.30-3(a)(12). Florence E. Harmon, Deputy Secretary. [FR Doc. E7-11368 Filed 6-12-07; 8:45 am] BILLING CODE 8010-01-P SMALL BUSINESS ADMINISTRATION [Disaster Declaration #10870] Vermont Disaster Number VT-00003 AGENCY: Small Business Administration. ACTION: Amendment 1. SUMMARY: This is an amendment of the Presidential declaration of a major disaster for Public Assistance Only for the State of Vermont (FEMA-1698-DR), dated 05/04/2007. *Incident:* Severe storms and flooding. *Incident Period:* 04/15/2007 through 04/21/2007. *Effective Date:* 06/04/2007. *Physical Loan Application Deadline Date:* 07/03/2007. ADDRESSES: Submit completed loan applications to: U.S. Small Business Administration, Processing and Disbursement Center, 14925 Kingsport Road, Fort Worth, TX 76155. FOR FURTHER INFORMATION CONTACT: A. Escobar, Office of Disaster Assistance, U.S. Small Business Administration, 409 3rd Street, SW., Suite 6050, Washington, DC 20416. SUPPLEMENTARY INFORMATION: The notice of the President's major disaster declaration for Private Non-Profit organizations in the State of Vermont, dated 05/04/2007, is hereby amended to include the following areas as adversely affected by the disaster. Primary Counties: Lamoille. All other information in the original declaration remains unchanged. (Catalog of Federal Domestic Assistance Number 59008) Herbert L. Mitchell, Associate Administrator for Disaster Assistance. [FR Doc. E7-11345 Filed 6-12-07; 8:45 am] BILLING CODE 8025-01-P SOCIAL SECURITY ADMINISTRATION Agency Information Collection Activities: Proposed Request and Comment Request The Social Security Administration
(SSA)publishes a list of information collection packages that will require clearance by the Office of Management and Budget
(OMB)in compliance with Public Law 104-13, the Paperwork Reduction Act of 1995, effective October 1, 1995. The information collection packages that may be included in this notice are for new information collections, approval of existing information collections, revisions to OMB-approved information collections, and extensions (no change) of OMB-approved information collections. SSA is soliciting comments on the accuracy of the agency's burden estimate; the need for the information; its practical utility; ways to enhance its quality, utility, and clarity; and on ways to minimize burden on respondents, including the use of automated collection techniques or other forms of information technology. Written comments and recommendations regarding the information collection(s) should be submitted to the OMB Desk Officer and the SSA Reports Clearance Officer. The information can be mailed, faxed or emailed to the individuals at the addresses and fax numbers listed below: OMB, Office of Management and Budget, *Attn:* Desk Officer for SSA, *Fax:* 202-395-6974, *e-mail address:* *OIRA_Submission@omb.eop.gov* . SSA, Social Security Administration, DCBFM, *Attn:* Reports Clearance Officer, 1333 Annex Building, 6401 Security Blvd., Baltimore, MD 21235, *Fax:* 410-965-6400, *e-mail address: OPLM.RCO@ssa.gov.* I. The information collections listed below are pending at SSA and will be submitted to OMB within 60 days from the date of this notice. Therefore, your comments should be submitted to SSA within 60 days from the date of this publication. You can obtain copies of the collection instruments by calling the SSA Reports Clearance Officer at 410-965-0454 or by writing to the address listed above. 1. National 800 Number—Claims Status—20 CFR 401.45—0960-NEW. SSA has established a process for authenticating the information of individuals who use the automated telephone services or speak to an agent to request information from SSA records. Prior to SSA responding to requests for personal information through the automated telephone services, we must authenticate the requester's information by obtaining the appropriate identification elements. This automated telephone service will provide callers with status of a Social Security claim which they have filed. All information provided will then be compared to the information contained in our records so that the appropriate claim is accessed and the respondent is given the status of that claim. Respondents are current Social Security beneficiaries. *Type of Request:* Request for a new information collection. *Number of Respondents:* 704,422. *Frequency of Response:* 1. *Average Burden per Response:* 1 minute. *Estimated Annual Burden:* 11,740 hours. 2. Function Report-Child: Birth to 1st Birthday (SSA-3375), Age 1 to 3rd Birthday (SSA-3376), Age 3 to 6th Birthday (SSA-3377), Age 6 to 12th Birthday (SSA-3378), and Age 12 to 18th Birthday (SSA-3379)—20 CFR 416.912—0960-0542. State Agency adjudicative teams use the information gathered by these forms in combination with other medical function evidence to form a complete picture of a child's ability to function. This information is used to help determine if a child is disabled, especially in cases in which disability cannot be found on medical grounds alone. The respondents are applicants for Title XVI childhood disability benefits and their caregivers. *Type of Request:* Extension of an OMB-approved information collection. *Number of Respondents:* 550,000. *Frequency of Response:* 1. *Average Burden per Response:* 20 minutes. *Estimated Annual Burden:* 183,333 hours. II. The information collections listed below have been submitted to OMB for clearance. Your comments on the information collections would be most useful if received by OMB and SSA within 30 days from the date of this publication. You can obtain a copy of the OMB clearance packages by calling the SSA Reports Clearance Officer at 410-965-0454, or by writing to the address listed above. 1. Notice Regarding Substitution of Party On Death of Claimant—Reconsideration of Disability Cessation—20 CFR 404.917-404.921 and 416.1407-416.1421—0960-0351. Form SSA-770 is used when a claimant dies before a determination is made on that person's request for reconsideration on his/her disability cessation. SSA seeks a qualified substitute party to pursue the appeal. If the qualified substitute party is located, the SSA-770 is used to collect information regarding whether to pursue or withdraw the reconsideration request. The information collected on the SSA-770 forms the basis of the decision to continue or discontinue the appeals process. Respondents are substitute applicants who are pursuing a reconsideration request for a deceased claimant. *Type of Request:* Extension of an OMB-approved information collection. *Number of Respondents:* 1,200. *Frequency of Response:* 1. *Average Burden Per Response:* 5 minutes. *Estimated Annual Burden:* 100 hours. 2. State Agency Report of Obligations for SSA Disability Programs (SSA-4513); Time Report of Personnel Services for Disability Determination Services (SSA-4514); State Agency Schedule of Equipment Purchased for SSA Disability Programs (SSA-871)—20 CFR 404.1626—0960-0421 (Correction to Burden Data). Forms SSA-4513, SSA-4514 and SSA-871 are used to collect data necessary for detailed analysis and evaluation of costs incurred by State Disability Determination Services
(DDS)in making determinations of disability for SSA. The data are also utilized in determining funding levels for each DDS. Respondents are State DDSs. *Type of Request:* Extension of an OMB-approved information collection. *Number of Respondents:* 52. *Estimated Annual Burden:* 756 hours. Respondents Frequency of response Average burden per response (minutes) Estimated annual burden (hours) SSA-4513 & Addendum 52 4 90 312 SSA-4514 52 4 90 312 SSA-871 52 4 30 104 Totals 52 728 Please note: We are correcting the number of respondents to this collection. In our notice published March 23, 2007 at 72 FR 13851 we initially state there are 54 State DDS's, whereas there are only 52. 3. Subpoena-Disability Hearing—20 CFR 404.916(b)(1) & 416.1416(b)(1)—0960-0428. Form SSA-1272-U4 is completed by State and Federal disability hearing officers to subpoena evidence or testimony in connection with hearings required by the Social Security Act. Actual issuance of the subpoena will be done by that appropriate delegated SSA official. Respondents are disability hearing officers. *Type of Request:* Extension of an OMB-approved information collection. *Number of Respondents:* 36. *Frequency of Response:* 1. *Average Burden per Response:* 30 minutes. *Estimated Annual Burden:* 18 hours. 4. Summary of Evidence—20 CFR 404.913(b), 404.914(a), 416.1707, 416.1313(b), 416.1414(a)—0960-0430. Form SSA-887 is completed by a Disability Hearing Officer
(DHO)from the claimant's State Disability Determination Service (DDS). The DHO summarizes all medical and vocational reports that were used to make the no-disability determination. This form, which is used to prepare for and conduct the disability hearing, is also made available to claimants so that they are aware of the basis for the no-disability decision and they can prepare for the reconsideration accordingly. Respondents are Disability Hearing Officers. *Type of Request:* Extension of an OMB-approved information collection. *Number of Respondents:* 49,000. *Frequency of Response:* 1. *Average Burden per Response:* 15 minutes. *Estimated Annual Burden:* 12,250 hours. 5. Information About Joint Checking/Savings Accounts—20 CFR 416.1201(b), 416.1208—0960-0461. The SSA-2574 is used to collect information when a Supplemental Security Income
(SSI)applicant/recipient objects to the assumption that he/she owns all or part of the funds in a joint checking or savings account which bears his or her name. Information about the account is collected from both the SSI applicant/recipient and other accountholder(s). These statements regarding ownership are required to determine whether the account is a resource of the SSI claimant. The amount of resources a person owns is one of the factors considered in determining eligibility for SSI. Respondents are applicants and recipients of SSI and individuals who are joint owners of financial accounts with SSI applicants/recipients. *Type of Request:* Extension of an OMB-approved information collection. *Number of Respondents:* 200,000. *Frequency of Response:* 1. *Average Burden per Response:* 7 minutes. *Estimated Annual Burden:* 23,333 hours. 6. Beneficiary Recontact Form—20 CFR 404.703, 404.705—0960-0502. SSA must ensure that eligibility for benefits continues after entitlement. Studies show that mothers/fathers who marry fail to report the marriage and or the fact that they no longer have a child entitled in their care. SSA uses the SSA-1588-OCR-SM to ask mothers/fathers about their marital status and children in care to detect overpayments and avoid continuing payment to those no longer entitled. Respondents are recipients of survivor mother/father Social Security benefits. *Type of Request:* Extension of an OMB-approved information collection. *Number of Respondents:* 133,400. *Frequency of Response:* 1. *Average Burden per Response:* 5 minutes. *Estimated Annual Burden:* 11,117 hours. 7. Earnings Record Information—20 CFR 404.801-404.803 and 404.821-404.822—0960-0505. The information collected by form SSA-L3231-C1 is used to ensure that the proper person is credited for working when earnings are reported for a minor under the age of 7 years. The respondents are businesses reporting earnings for children under age 7. *Type of Information Collection:* Extension of an OMB-approved information collection. *Number of Respondents:* 20,000. *Frequency of Response:* 1. *Average Burden per Response:* 10 minutes. *Estimated Annual Burden:* 3,333 hours. 8. Wage Reports and Pension Information—20 CFR 422.122(b)—0960-0547. The information collected through 20 CFR 422.122(b) is used by SSA to identify the requestor of pension plan information and to confirm the individual is entitled to the data SSA provides. Respondents are requestors of pension plan information. *Type of Request:* Extension of an OMB-approved information collection. *Number of Respondents:* 600. *Frequency of Response:* 1. *Average Burden per Response:* 30 minutes. *Estimated Annual Burden:* 300 hours. 9. Youth Transition Process Demonstration Evaluation Data Collection—0960-0687. Background The Youth Transition Demonstration YTD projects are intended to help young people with disabilities make the transition from school to work. By waiving certain disability program rules and offering services to youth who are either receiving disability benefits or at risk of receiving them, these projects are expected to encourage youth to work and/or continue their education. YTD projects will be fully implemented in 10 sites across the country. The evaluation will produce empirical evidence on the impacts of the waivers and project services not only on educational attainment, employment, earnings, and receipt of benefits by youth with disabilities but also on the Social Security Trust Fund and federal income tax revenues. This type of project is authorized by sections 1110 and 234 of the Social Security Act. Project Description Given the importance of estimating YTD impacts as accurately as possible, the evaluation will be conducted using rigorous analytic methods based on the random assignment of youth to a treatment or control group. Several data collection efforts are planned. These include
(1)baseline interviews with youth and their parents or guardians prior to random assignment;
(2)follow-up interviews at 12 and 36 months after random assignment;
(3)interviews and/or roundtable discussions with local program administrators, program supervisors, and service delivery staff; and
(4)focus groups of youth, their parents, and service providers. The respondents will be youth with disabilities who have enrolled in the project, their parents or guardians, program staff, and service providers. *Type of Request:* Revision of an existing OMB Clearance. Data collection year Collection Number of respondents Responses per respondent Average burden per response (hours) Total response burden (hours) 2007 Baseline 962 1 0.55 529 Informed Consent 962 1 0.83 80 12 month follow-up 1 437 1 0.83 363 Focus group 140 1 1.5 210 Program staff/service provider 32 1 1 32 Total 2007 1,214 1 We conduct follow-up interviews only for those baseline respondents who sign consent forms. 10. Request for Program Consultation—20 CFR 404.1601-1661—0960-New. The Disability Determination Services
(DDS)offices are staffed by State employees who perform disability determinations for applicants for Social Security disability benefits under Title II and Title XVI of the Social Security Act. SSA's federal regional quality assurance office has the authority to review DDS determinations, to assess errors, and to return cases for corrective action by the DDS. The information collected on the Request for Program Consultation
(RPC)will be used by the DDS's that request a review of the regional quality assurance evaluations. The DDS's use the RPC to present their rationale that supports their determinations. The information collected includes a short rationale and policy citations supporting their rebuttal. The RPC team will use the information to reassess their initial determination. The respondents are DDS's who request a review of the regional quality assurance determination. *Type of Request:* Request for a new information collection. *Number of Respondents:* 4,500. *Frequency of Response:* 1. *Average Burden per Response:* 50 minutes. *Estimated Annual Burden:* 3,750 hours. 11. Request to Decision Review Board To Vacate the Administrative Law Judge Dismissal of Hearing—20 CFR 405.427—0960-NEW. The information collected on Form SSA-525 will be used by Social Security Administration's Decision Review Board (Board) when a hearing on a claim for Title II or Title XVI disability payments is dismissed and the claimant requests that the dismissal be vacated. The Board will use this information to
(1)establish the continued involvement of the requester in his or her claim;
(2)consider the requester's arguments for vacating the dismissal; and
(3)vacate or decline to vacate the administrative law judge's dismissal order. The respondents are Social Security disability or Supplemental Security Income
(SSI)claimants who are requesting that the dismissal be vacated. *Type of Request:* Request for a new information collection. *Number of Respondents:* 30,000. *Frequency of Response:* 1. *Average Burden Per Response:* 10 minutes. *Estimated Annual Burden:* 5,000 hours. 12. Medical History and Disability Report, Disabled Child—20 CFR 416.912—0960-0577. The Social Security Act requires claimants to furnish medical and other evidence to prove they are disabled. The form SSA-3820 is used to obtain various types of information about a child's condition, his/her treating sources and/or other medical sources of evidence. The information collected on the SSA-3820 is needed for the determination of disability by the State DDSs. The respondents are applicants for Title XVI child disability benefits. *Type of Request:* Revision to an OMB-approved information collection. Collection format Number of respondents Frequency of responses Average burden per responses Estimated annual burden
(hour)SSA-3820 (Paper Form) 500 1 1 hour 500 Electronic Disability Collection System
(EDCS)422,000 1 34 minutes 239,133 i3820 (Internet) 39,500 1 2 hours 79,000 Totals 462,000 318,633 13. Social Security Disability Report—20 CFR 404.1512 & 416.912—0960-0579. The Social Security Administration requires applicants for disability payments to furnish medical, work history, and other evidence or information indicating they have an impairment which is disabling. This information is collected by form SSA-3368, the Adult Disability Report, and is used by State DDS's to make disability determinations for SSA. The respondents are applicants for Title II and Title XVI disability benefits. These applicants may complete the form using any of the following modalities:
(1)The traditional paper form;
(2)an interview with an SSA field office representative, using the EDCS;
(3)the Internet (i3368); and
(4)a modality, the i3368-PRO, an Internet form designed to be completed by representatives of applicants for disability payments. The latter three versions of the form collect the same information as the paper form, but may be formatted differently and include certain enhancements (ex: self-help screens) to guide the claimant or interviewer through the application process. *Type of Request:* Revision to an OMB-approved information collection. Collection format Number of respondents Frequency of response Average burden per response (hours) Estimated annual burden (hours) SSA-3368 (Paper version) 9,364 1 1 9,364 Field office/EDCS 3,138,920 1 1 3,138,920 i3368 (Internet version; Hour burden varies from 1 1/2 -3 hours, depending on information required) 101,135 1 2 1/2 252,837 i3368-PRO 101,135 1 1 1/2 151,702 Totals 3,350,554 3,552,823 14. Certification of Contents of Document(s) or Record(s)—20 CFR 404.715ff—0960-0689. SSA must secure evidence necessary for individuals to establish rights to benefits. Some of the types of evidence needed are evidence of age relationship, citizenship, marriage, death, and military service. Form SSA-704 allows SSA employees, state record custodians, and other custodians of evidentiary documents to record information from documents and records to establish these types of evidence. SSA employees use this form but it is also used by state record custodians and other custodians of evidentiary documents. *Type of Request:* Extension of an OMB-approved information collection. *Number of Respondents:* 4,800. *Average Burden per Response:* 10 minutes. *Estimated Annual Burden:* 800. 15. Waiver of Your Right to Personal Appearance before an Administrative Law Judge—20 CFR 404.948(b)(l)(i) and 416.1448(b)(l)(i)—0960-0284. Each claimant has a statutory right to appear in person (or through a representative) and present evidence about his/her claim at a hearing before an Administrative Law Judge (ALJ). If a claimant wishes to waive his/her statutory right to appear before an ALJ, he/she must complete a written request. The claimant may use Form HA-4608 for this request. The information collected is used to document an individual's claim to show that an oral hearing is not preferred in the appellate process. The respondents are applicants for Title II benefits and Title XVI payments who request a hearing. *Number of Respondents:* 12,000. *Frequency of Response:* 1. *Average Burden per Response:* 2 minutes. *Estimated Annual Burden:* 400 hours. Dated: June 7, 2007. Elizabeth A. Davidson, Reports Clearance Officer, Social Security Administration. [FR Doc. E7-11383 Filed 6-12-07; 8:45 am] BILLING CODE 4191-02-P DEPARTMENT OF STATE [Public Notice 5833] Bureau of Political-Military Affairs: Directorate of Defense Trade Controls; Notifications to the Congress of Proposed Commercial Export Licenses SUMMARY: Notice is hereby given that the Department of State has forwarded the attached Notifications of Proposed Export Licenses to the Congress on the dates indicated pursuant to sections 36(c) and 36(d) and in compliance with section 36(f) of the Arms Export Control Act (22 U.S.C. 2776). DATES: *Effective Date:* As shown on each of the 13 letters. FOR FURTHER INFORMATION CONTACT: Ms. Susan M. Clark, Director, Office of Defense Trade Controls Licensing, Directorate of Defense Trade Controls, Bureau of Political-Military Affairs, Department of State
(202)663-2023. SUPPLEMENTARY INFORMATION: Section 36(f) of the Arms Export Control Act mandates that notifications to the Congress pursuant to sections 36(c) and 36(d) must be published in the **Federal Register** when they are transmitted to Congress or as soon thereafter as practicable. March 30, 2007. Hon. Nancy Pelosi, *Speaker of the House of Representatives.* Dear Madam Speaker: Pursuant to Section 36(c) of the Arms Export Control Act, I am transmitting, herewith, certification of a proposed license for the export of defense articles or defense services sold commercially under a contract in the amount of $50,000,000 or more. The transaction contained in the attached certification involves the export of technical data, defense services and defense articles for the VINASAT-1 commercial communications satellite to Vietnam. The United States Government is prepared to license the export of these items having taken into account political, military, economic, human rights and arms control considerations. More detailed information is contained in the formal certification which, though unclassified, contains business information submitted to the Department of State by the applicant, publication of which could cause competitive harm to the United States firm concerned. Sincerely, Jeffrey T. Bergner, *Assistant Secretary Legislative Affairs* . Enclosure: Transmittal No. DDTC 016-07. March 30, 2007. Hon. Nancy Pelosi, *Speaker of the House of Representatives.* Dear Madam Speaker: Pursuant to Section 36(c) of the Arms Export Control Act, I am transmitting, herewith, certification of a proposed license for the export of defense articles and defense services in the amount of $50,000,000 or more. The transactions contained in the attached certification concern future commercial activities with Russia, Ukraine and Norway related to the launch of all commercial and foreign non-commercial satellites from the Pacific Ocean utilizing a modified oil platform. The United States Government is prepared to license the export of these items having taken into account political, military, economic, human rights and arms control considerations. More detailed information is contained in the formal certification which, though unclassified, contains business information submitted to the Department of State by the applicant, publication of which could cause competitive harm to the United States firm concerned. Sincerely, Jeffrey T. Bergner, *Assistant Secretary Legislative Affairs.* Enclosure: Transmittal No. DDTC 035-07. March 30, 2007. Hon. Nancy Pelosi, *Speaker of the House of Representatives.* Dear Madam Speaker: Pursuant to Section 36(c) of the Arms Export Control Act, I am transmitting, herewith, certification of a proposed license for the export of defense articles and defense services in the amount of $50,000,000 or more. The transactions contained in the attached certification concern future commercial activities with Russia related to the launch of all commercial and foreign non-commercial satellites from Kazakhstan. The United States Government is prepared to license the export of these items having taken into account political, military, economic, human rights and arms control considerations. More detailed information is contained in the formal certification which, though unclassified, contains business information submitted to the Department of State by the applicant, publication of which could cause competitive harm to the United States firm concerned. Sincerely, Jeffrey T. Bergner, *Assistant Secretary Legislative Affairs.* Enclosure: Transmittal No. DDTC 036-07. March 30, 2007. Hon. Nancy Pelosi, *Speaker of the House of Representatives.* Dear Madam Speaker: Pursuant to Section 36(c) of the Arms Export Control Act, I am transmitting, herewith, certification of a proposed license for the export of defense articles and defense services in the amount of $100,000,000 or more. The transactions contained in the attached certification concern future commercial activities related to the co-development of the Galaxy Express space launch vehicle upgrade program for Japan. The United States Government is prepared to license the export of these items having taken into account political, military, economic, human rights and arms control considerations. More detailed information is contained in the formal certification which, though unclassified, contains business information submitted to the Department of State by the applicant, publication of which could cause competitive harm to the United States firm concerned. Sincerely, Jeffrey T. Bergner, *Assistant Secretary Legislative Affairs.* Enclosure: Transmittal No. DDTC 037-07. April 26, 2007. Hon. Nancy Pelosi, *Speaker of the House of Representatives.* Dear Madam Speaker: Pursuant to Section 36(d) of the Arms Export Control Act, I am transmitting, herewith, certification of a proposed manufacturing license agreement for the manufacture of significant military equipment abroad. The transaction contained in the attached certification involves the export of technical data, defense articles, and defense services to Germany for the manufacture of chemical defense fabrics for end-use by the Ministries of Defense within the authorized sales territory. The United States Government is prepared to license the export of these items having taken into account political, military, economic, human rights and arms control considerations. More detailed information is contained in the formal certification, which, though unclassified, contains business information submitted to the Department of State by the applicant, publication of which could cause competitive harm to the United States firm concerned. Sincerely, Jeffrey T. Bergner, *Assistant Secretary Legislative Affairs.* Enclosure: Transmittal No. DDTC 001-07. April 26, 2007. Hon. Nancy Pelosi, *Speaker of the House of Representatives.* Dear Madam Speaker: Pursuant to Section 36(c) and 36(d) of the Arms Export Control Act, I am transmitting, herewith, certification of a proposed manufacturing license agreement for the manufacture of significant military equipment abroad and the export of defense articles or defense services in the amount of $100,000,000 or more. The transaction described in the attached certification involves the transfer of technical information, including hardware and services for licensed production of the Evolved SeaSparrow Missile
(ESSM)for ultimate sale to and end-use by the Japan Defense Agency (JDA). The United States Government is prepared to license the export of these items having taken into account political, military, economic, human rights and arms control considerations. More detailed information is contained in the formal certification which, though unclassified, contains business information submitted to the Department of State by the applicant, publication of which could cause competitive harm to the United States firm concerned. Sincerely, Jeffrey T. Bergner, *Assistant Secretary Legislative Affairs.* Enclosure: Transmittal No. DDTC 013-07. April 26, 2007. Hon. Nancy Pelosi, *Speaker of the House of Representatives.* Dear Madam Speaker: Pursuant to Section 36(c) of the Arms Export Control Act, I am transmitting, herewith, certification of a proposed license for the export of defense articles or defense services sold commercially under contract in the amount of $50,000,000 or more. The transaction contained in the attached certification involves the export of technical data and defense services related to the Rolling Airframe Missile
(RAM)MK 31 Guided Missile Weapon System
(GMWS)for the KDX-II Destroyer and LPX Transport Programs for end use by the Republic of Korea Ministry of National Defense. The United States Government is prepared to license the export of these items having taken into account political, military, economic, human rights and arms control considerations. More detailed information is contained in the formal certification which, though unclassified, contains business information submitted to the Department of State by the applicant, publication of which could cause competitive harm to the United States firm concerned. Sincerely, Jeffrey T. Bergner, *Assistant Secretary Legislative Affairs.* Enclosure: Transmittal No. DDTC 014-07. May 9, 2007. Hon. Nancy Pelosi, *Speaker of the House of Representatives.* Dear Madam Speaker: Pursuant to Section 36(d) of the Arms Export Control Act, I am transmitting, herewith, certification of a proposed manufacturing license agreement for the manufacture of significant military equipment abroad. The transaction contained in the attached certification involves the export of technical data, defense articles, and defense services to the United Kingdom for manufacture of the M53 Nuclear-Biological-Chemical Improved Protective mask for end-use by the U.S. Army. The United States Government is prepared to license the export of these items having taken into account political, military, economic, human rights and arms control considerations. More detailed information is contained in the formal certification which, though unclassified, contains business information submitted to the Department of State by the applicant, publication of which could cause competitive harm to the United States firm concerned. Sincerely, Jeffrey T. Bergner, *Assistant Secretary Legislative Affairs.* Enclosure: Transmittal No. DDTC 002-07. May 9, 2007. Hon. Nancy Pelosi, *Speaker of the House of Representatives.* Dear Madam Speaker: Pursuant to Section 36(c) of the Arms Export Control Act, I am transmitting, herewith, certification of a proposed export of defense articles, technical data and defense services for major defense equipment in an amount of $25,000,000 or more. The transaction contained in the attached certification involves the export of one C-130J-30 aircraft to Denmark. The United States Government is prepared to license the export of these items having taken into account political, military, economic, human rights and arms control considerations. More detailed information is contained in the formal certification which, though unclassified, contains business information submitted to the Department of State by the applicant, publication of which could cause competitive harm to the United States firm concerned. Sincerely, Jeffrey T. Bergner, *Assistant Secretary Legislative Affairs.* Enclosure: Transmittal No. DDTC 007-07. May 9, 2007. Hon. Nancy Pelosi, *Speaker of the House of Representatives.* Dear Madam Speaker: Pursuant to Section 36(c) of the Arms Export Control Act, I am transmitting, herewith, certification of a proposed amendment to manufacturing license agreement for the manufacture of defense articles abroad in the amount of $100,000,000 or more. The transaction described in the attached certification involves the transfer of technical data, assistance and manufacturing know-how to Turkey for the manufacture of the AN/ALQ-178(V)5+ Self Protection Electronic Warfare System (SPEWS II) for Turkish F16 Aircraft. The United States Government is prepared to license the export of these items having taken into account political, military, economic, human rights and arms control considerations. More detailed information is contained in the formal certification which, though unclassified, contains business information submitted to the Department of State by the applicant, publication of which could cause competitive harm to the United States firm concerned. Sincerely, Jeffrey T. Bergner, *Assistant Secretary Legislative Affairs.* Enclosure: Transmittal No. DDTC 024-07. May 18, 2007. Hon. Nancy Pelosi, *Speaker of the House of Representatives.* Dear Madam Speaker: Pursuant to Section 36(c) of the Arms Export Control Act, I am transmitting, herewith, certification of a proposed license for the export of defense articles or defense services sold commercially under contract in the amount of $100,000,000 or more. The transaction contained in the attached certification involves defense services associated with the Ballistic Missile Defense
(BMD)Expansion Project for the Japan Air Defense Ground Environment (JADGE) Program for end use by the Japan Defense Ministry. The United States Government is prepared to license the export of these items having taken into account political, military, economic, human rights and arms control considerations. More detailed information is contained in the formal certification which, though unclassified, contains business information submitted to the Departemnt of State by the applicant, publication of which could cause competitive harm to the United States firm concerned. Sincerely, Jeffrey T. Bergner, *Assistant Secretary Legislative Affairs.* Enclosure: Transmittal No. DDTC 012-07. May 18, 2007. Hon. Nancy Pelosi, *Speaker of the House of Representatives.* Dear Madam Speaker: Pursuant to Section 36(c) of the Arms Export Control Act, I am transmitting, herewith, certification of a proposed manufacturing license agreement for the manufacture of defense articles abroad in the amount of $50,000,000 or more. The transaction contained in the attached certification involves the transfer of technical data, assistance and manufacturing know-how to Israel for the manufacture of J79 engine parts for integration into F4, F104, and Kfir Military Fighter Aircraft. The United States Government is prepared to license the export of these items having taken into account political, military, economic, human rights and arms control considerations. More detailed information is contained in the formal certification which, though unclassified, contains business information submitted to the Department of State by the applicant, publication of which could cause competitive harm to the United States firm concerned. Sincerely, Jeffrey T. Bergner, *Assistant Secretary Legislative Affairs.* Enclosure: Transmittal No. DDTC 020-07. May 18, 2007. Hon. Nancy Pelosi, *Speaker of the House of Representatives.* Dear Madam Speaker: Pursuant to Section 36(c) of the Arms Export Control Act, I am transmitting, herewith, certification of a proposed technical assistance agreement for the export of technical data, defense services, and defense articles in the amount of $100,000,000 or more. The transaction contained in the attached certification involves the export of technical data, defense services, and defense articles to support sale of CH-47F Chinook helicopters to the Netherlands and the re-manufacture and modification of the Netherlands' CH-47D Chinook helicopters to the CH-47F configuration in support of Operation Enduring Freedom. The United States Government is prepared to license the export of these items having taken into account political, military, economic, human rights and arms control considerations. More detailed information is contained in the formal certification which, though unclassified, contains business information submitted to the Department of State by the applicant, publication of which could cause competitive harm to the United States firm concerned. Sincerely, Jeffrey T. Bergner, *Assistant Secretary Legislative Affairs.* Enclosure: Transmittal No. DDTC 030-07. Dated: June 5, 2007. Susan M. Clark, Director, Office of Defense Trade Controls Licensing, Department of State. [FR Doc. E7-11507 Filed 6-12-07; 8:45 am] BILLING CODE 4710-25-P DEPARTMENT OF STATE [Public Notice 5830] Culturally Significant Objects Imported for Exhibition Determinations: “Eternal Ancestors: Art of the Central African Reliquary” *Summary:* Notice is hereby given of the following determinations: Pursuant to the authority vested in me by the Act of October 19, 1965 (79 Stat. 985; 22 U.S.C. 2459), Executive Order 12047 of March 27, 1978, the Foreign Affairs Reform and Restructuring Act of 1998 (112 Stat. 2681, *et seq.* ; 22 U.S.C. 6501 note, *et seq.* ), Delegation of Authority No. 234 of October 1, 1999, Delegation of Authority No. 236 of October 19, 1999, as amended, and Delegation of Authority No. 257 of April 15, 2003 [68 FR 19875], I hereby determine that the objects to be included in the exhibition “Eternal Ancestors: Art of the Central African Reliquary”, imported from abroad for temporary exhibition within the United States, are of cultural significance. The objects are imported pursuant to loan agreements with the foreign owners or custodians. I also determine that the exhibition or display of the exhibit objects at The Metropolitan Museum of Art, New York, New York, from on or about October 2, 2007, until on or about March 2, 2008, and at possible additional exhibitions or venues yet to be determined, is in the national interest. Public Notice of these Determinations is ordered to be published in the **Federal Register** . *For Further Information Contact:* For further information, including a list of the exhibit objects, contact Paul Manning, Attorney-Adviser, Office of the Legal Adviser, U.S. Department of State (telephone:
(202)453-8050). The address is U.S. Department of State, SA-44, 301 4th Street, SW., Room 700, Washington, DC 20547-0001. Dated: June 5, 2007. C. Miller Crouch, Principal Deputy Assistant Secretary for Educational and Cultural Affairs, Department of State. [FR Doc. E7-11406 Filed 6-12-07; 8:45 am] BILLING CODE 4710-05-P DEPARTMENT OF STATE [Public Notice 5831] Culturally Significant Objects Imported for Exhibition Determinations: “Louvre Atlanta: The Louvre and the Ancient World; Eye of Josephine; and Houdon in France and America” *Summary:* Notice is hereby given of the following determinations: Pursuant to the authority vested in me by the Act of October 19, 1965 (79 Stat. 985; 22 U.S.C. 2459), Executive Order 12047 of March 27, 1978, the Foreign Affairs Reform and Restructuring Act of 1998 (112 Stat. 2681, *et seq.* ; 22 U.S.C. 6501 note, *et seq.* ), Delegation of Authority No. 234 of October 1, 1999, Delegation of Authority No. 236 of October 19, 1999, as amended, and Delegation of Authority No. 257 of April 15, 2003 [68 FR 19875], I hereby determine that the objects to be included in the exhibition Louvre Atlanta: The Louvre and The Ancient World; Eye of Josephine; and Houdon in France and America,” imported from abroad for temporary exhibition within the United States, are of cultural significance. The objects are imported pursuant to a loan agreement with the foreign owner or custodian. I also determine that the exhibition or display of The Louvre and The Ancient World exhibit objects at the High Museum of Art, Atlanta, Georgia, from on or about October 16, 2007, until on or about September 7, 2008; the exhibition or display of the Eye of Josephine exhibit objects at the High Museum of Art, Atlanta, Georgia, from on or about October 16, 2007, until on or about May 18, 2008; and the exhibition or display of the Houdon in France and America objects at the High Museum of Art, Atlanta, Georgia, from on or about June 7, 2008 until on or about September 7, 2008, and the Denver Art Museum, Denver, Colorado, from on or about October 12, 2008, until on or about January 4, 2009; and at possible additional exhibitions or venues yet to be determined, is in the national interest. Public Notice of these Determinations is ordered to be published in the **Federal Register** . *For Further Information Contact:* For further information, including a list of the exhibit objects, contact Wolodymyr Sulzynsky, Attorney-Adviser, Office of the Legal Adviser, U.S. Department of State (telephone:
(202)453-8050). The address is U.S. Department of State, SA-44, 301 4th Street, SW., Room 700, Washington, DC 20547-0001. Dated: June 5, 2007. C. Miller Crouch, Principal Deputy Assistant Secretary for Educational and Cultural Affairs, Department of State. [FR Doc. E7-11403 Filed 6-12-07; 8:45 am] BILLING CODE 4710-05-P DEPARTMENT OF STATE [Public Notice 5832] Culturally Significant Objects Imported for Exhibition Determinations: “Oceanic Art” *Summary:* Notice is hereby given of the following determinations: Pursuant to the authority vested in me by the Act of October 19, 1965 (79 Stat. 985; 22 U.S.C. 2459), Executive Order 12047 of March 27, 1978, the Foreign Affairs Reform and Restructuring Act of 1998 (112 Stat. 2681, *et seq.* ; 22 U.S.C. 6501 note, *et seq.* ), Delegation of Authority No. 234 of October 1, 1999, Delegation of Authority No. 236 of October 19, 1999, as amended, and Delegation of Authority No. 257 of April 15, 2003 [68 FR 19875], I hereby determine that the objects to be included in the exhibition “Oceanic Art”, imported from abroad for temporary exhibition within the United States, are of cultural significance. The objects are imported pursuant to a loan agreement with the foreign owner or custodian. I also determine that the exhibition or display of the exhibit objects at The Metropolitan Museum of Art, New York, New York, from on or about August 1, 2007, until on or about August 31, 2010, and at possible additional exhibitions or venues yet to be determined, is in the national interest. Public Notice of these Determinations is ordered to be published in the **Federal Register** . *For Further Information Contact:* For further information, including a list of the exhibit objects, contact Paul Manning, Attorney-Adviser, Office of the Legal Adviser, U.S. Department of State (telephone:
(202)453-8050). The address is U.S. Department of State, SA-44, 301 4th Street, SW., Room 700, Washington, DC 20547-0001. Dated: June 6, 2007. C. Miller Crouch, Principal Deputy Assistant Secretary for Educational and Cultural Affairs, Department of State. [FR Doc. E7-11405 Filed 6-12-07; 8:45 am] BILLING CODE 4710-05-P DEPARTMENT OF TRANSPORTATION Federal Motor Carrier Safety Administration [Docket No. FMCSA-2007-27515] Qualification of Drivers; Exemption Applications; Vision AGENCY: Federal Motor Carrier Safety Administration (FMCSA), DOT. ACTION: Notice of final disposition. SUMMARY: FMCSA announces its decision to exempt 24 individuals from the vision requirement in the Federal Motor Carrier Safety Regulations (FMCSRs). The exemptions will enable these individuals to operate commercial motor vehicles
(CMVs)in interstate commerce without meeting the prescribed vision standard. The Agency has concluded that granting these exemptions will provide a level of safety that is equivalent to, or greater than, the level of safety maintained without the exemptions for these CMV drivers. DATES: The exemptions are effective June 13, 2007. The exemptions expire on June 15, 2009. FOR FURTHER INFORMATION CONTACT: Dr. Mary D. Gunnels, Chief, Physical Qualifications Division, 202-366-4001, FMCSA, Room W64-224, U.S. Department of Transportation, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001. Office hours are from 8:30 a.m. to 5 p.m. Monday through Friday, except Federal holidays. SUPPLEMENTARY INFORMATION: Electronic Access You may see all the comments online through the Document Management System
(DMS)at *http://dmses.dot.gov.* *Docket:* For access to the docket to read background documents or comments received, go to *http://dms.dot.gov* at any time or Room W12-140 on the ground level of the West Building, 1200 New Jersey Avenue, SE., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. *Privacy Act:* Anyone may search the electronic form of all comments received into any of DOT's dockets by the name of the individual submitting the comment (or of the person signing the comment, if submitted on behalf of an association, business, labor union, or other entity). You may review DOT's complete Privacy Act Statement in the **Federal Register** (65 FR 19477, Apr. 11, 2000). This statement is also available at *http://dms.dot.gov* . Background On April 30, 2007, FMCSA published a notice of receipt of exemption applications from certain individuals, and requested comments from the public (72 FR 21313). That notice listed 25 applicants' case histories. The 25 individuals applied for exemptions from the vision requirement in 49 CFR 391.41(b)(10), for drivers who operate CMVs in interstate commerce. Under 49 U.S.C. 31136(e) and 31315, FMCSA may grant an exemption for a 2-year period if it finds “such exemption would likely achieve a level of safety that is equivalent to, or greater than, the level that would be achieved absent such exemption.” The statute also allows the Agency to renew exemptions at the end of the 2-year period. Accordingly, FMCSA has evaluated the 25 applications on their merits and made a determination to grant exemptions to 24 of them. One applicant, Robert J. MacInnis, informed FMCSA that he was involved in a crash while operating a privately owned vehicle on May 2, 2007. Consequently, his driver's license was suspended for 45 days effective May 9, 2007. Due to this being a disqualifying offense, the Agency will not be granting him an exemption at this time. The comment period closed on May 30, 2007. Vision and Driving Experience of the Applicants The vision requirement in the FMCSRs provides: A person is physically qualified to drive a commercial motor vehicle if that person has distant visual acuity of at least 20/40 (Snellen) in each eye without corrective lenses or visual acuity separately corrected to 20/40 (Snellen) or better with corrective lenses, distant binocular acuity of a least 20/40 (Snellen) in both eyes with or without corrective lenses, field of vision of at least 70° in the horizontal meridian in each eye, and the ability to recognize the colors of traffic signals and devices showing standard red, green, and amber (49 CFR 391.41(b)(10)). FMCSA recognizes that some drivers do not meet the vision standard, but have adapted their driving to accommodate their vision limitation and demonstrated their ability to drive safely. The 25 exemption applicants listed in this notice are in this category. They are unable to meet the vision standard in one eye for various reasons, including amblyopia, macular scar, retinal damage from broken blood vessels, prosthesis, latent nystagmus, optic nerve injury, histoplasmosis syndrome, ocular hypertension, glaucoma and loss of vision due to trauma. In most cases, their eye conditions were not recently developed. All but seven of the applicants were either born with their vision impairments or have had them since childhood. The seven individuals who sustained their vision conditions as adults have had them for periods ranging from 7 to 40 years. Although each applicant has one eye which does not meet the vision standard in 49 CFR 391.41(b)(10), each has at least 20/40 corrected vision in the other eye, and in a doctor's opinion, has sufficient vision to perform all the tasks necessary to operate a CMV. Doctors' opinions are supported by the applicants' possession of valid commercial driver's licenses
(CDLs)or non-CDLs to operate CMVs. Before issuing CDLs, States subject drivers to knowledge and skills tests designed to evaluate their qualifications to operate a CMV. All these applicants satisfied the testing standards for their State of residence. By meeting State licensing requirements, the applicants demonstrated their ability to operate a commercial vehicle, with their limited vision, to the satisfaction of the State. While possessing a valid CDL or non-CDL, these 25 drivers have been authorized to drive a CMV in intrastate commerce, even though their vision disqualified them from driving in interstate commerce. They have driven CMVs with their limited vision for careers ranging from 7 to 40 years. In the past 3 years, three of the drivers have had convictions for traffic violations and one of them was involved in a crash. The qualifications, experience, and medical condition of each applicant were stated and discussed in detail in the April 30, 2007 notice (72 FR 21313). Basis for Exemption Determination Under 49 U.S.C. 31136(e) and 31315, FMCSA may grant an exemption from the vision standard in 49 CFR 391.41(b)(10) if the exemption is likely to achieve an equivalent or greater level of safety than would be achieved without the exemption. Without the exemption, applicants will continue to be restricted to intrastate driving. With the exemption, applicants can drive in interstate commerce. Thus, our analysis focuses on whether an equal or greater level of safety is likely to be achieved by permitting each of these drivers to drive in interstate commerce as opposed to restricting him or her to driving in intrastate commerce. To evaluate the effect of these exemptions on safety, FMCSA considered not only the medical reports about the applicants' vision, but also their driving records and experience with the vision deficiency. To qualify for an exemption from the vision standard, FMCSA requires a person to present verifiable evidence that he/she has driven a commercial vehicle safely with the vision deficiency for the past 3 years. Recent driving performance is especially important in evaluating future safety, according to several research studies designed to correlate past and future driving performance. Results of these studies support the principle that the best predictor of future performance by a driver is his/her past record of crashes and traffic violations. Copies of the studies may be found at docket number FMCSA-98-3637. We believe we can properly apply the principle to monocular drivers, because data from the Federal Highway Administration's
(FHWA)former waiver study program clearly demonstrate the driving performance of experienced monocular drivers in the program is better than that of all CMV drivers collectively. (See 61 FR 13338, 13345, March 26, 1996). The fact that experienced monocular drivers demonstrated safe driving records in the waiver program supports a conclusion that other monocular drivers, meeting the same qualifying conditions as those required by the waiver program, are also likely to have adapted to their vision deficiency and will continue to operate safely. The first major research correlating past and future performance was done in England by Greenwood and Yule in 1920. Subsequent studies, building on that model, concluded that crash rates for the same individual exposed to certain risks for two different time periods vary only slightly. (See Bates and Neyman, University of California Publications in Statistics, April 1952.) Other studies demonstrated theories of predicting crash proneness from crash history coupled with other factors. These factors—such as age, sex, geographic location, mileage driven and conviction history—are used every day by insurance companies and motor vehicle bureaus to predict the probability of an individual experiencing future crashes. (See Weber, Donald C., “Accident Rate Potential: An Application of Multiple Regression Analysis of a Poisson Process,” Journal of American Statistical Association, June 1971) A 1964 California Driver Record Study prepared by the California Department of Motor Vehicles concluded that the best overall crash predictor for both concurrent and nonconcurrent events is the number of single convictions. This study used 3 consecutive years of data, comparing the experiences of drivers in the first 2 years with their experiences in the final year. Applying principles from these studies to the past 3-year record of the 25 applicants, two of the applicants had traffic violations for speeding, one applicant failed to obey a traffic sign, and one applicant was involved in a crash. The applicants achieved this record of safety while driving with their vision impairment, demonstrating the likelihood that they have adapted their driving skills to accommodate their condition. As the applicants' ample driving histories with their vision deficiencies are good predictors of future performance, FMCSA concludes their ability to drive safely can be projected into the future. We believe the applicants' intrastate driving experience and history provide an adequate basis for predicting their ability to drive safely in interstate commerce. Intrastate driving, like interstate operations, involves substantial driving on highways on the interstate system and on other roads built to interstate standards. Moreover, driving in congested urban areas exposes the driver to more pedestrian and vehicular traffic than exists on interstate highways. Faster reaction to traffic and traffic signals is generally required because distances between them are more compact. These conditions tax visual capacity and driver response just as intensely as interstate driving conditions. The veteran drivers in this proceeding have operated CMVs safely under those conditions for at least 3 years, most for much longer. Their experience and driving records lead us to believe that each applicant is capable of operating in interstate commerce as safely as he/she has been performing in intrastate commerce. Consequently, FMCSA finds that exempting these applicants from the vision standard in 49 CFR 391.41(b)(10) is likely to achieve a level of safety equal to that existing without the exemption. For this reason, the Agency is granting the exemptions for the 2-year period allowed by 49 U.S.C. 31136(e) and 31315 to 24 of the applicants listed in the notice of April 30, 2007 (72 FR 21313). We recognize that the vision of an applicant may change and affect his/her ability to operate a CMV as safely as in the past. As a condition of the exemption, therefore, FMCSA will impose requirements on the 24 individuals consistent with the grandfathering provisions applied to drivers who participated in the Agency's vision waiver program. Those requirements are found at 49 CFR 391.64(b) and include the following:
(1)That each individual be physically examined every year
(a)by an ophthalmologist or optometrist who attests that the vision in the better eye continues to meet the standard in 49 CFR 391.41(b)(10), and
(b)by a medical examiner who attests that the individual is otherwise physically qualified under 49 CFR 391.41;
(2)that each individual provide a copy of the ophthalmologist's or optometrist's report to the medical examiner at the time of the annual medical examination; and
(3)that each individual provide a copy of the annual medical certification to the employer for retention in the driver's qualification file, or keep a copy in his/her driver's qualification file if he/she is self-employed. The driver must also have a copy of the certification when driving, for presentation to a duly authorized Federal, State, or local enforcement official. Discussion of Comments FMCSA received no comments in this proceeding. Conclusion Based upon its evaluation of the 25 exemption applications, FMCSA exempts Roosevelt Bell, Jr., David K. Boswell, Melvin M. Carter, Bernabe V. Cerda, Michael S. Crawford, Rex A. Dyer, Patrick J. Goebel, Thomas A. Gotto, Louis W. Henderson, Jr., William P. Holloman, Wilbur J. Johnson, Joseph W. Mayes, Larry L. Morseman, Earl R. Neugebauer, Luis M. Ramos, Kenneth C. Reeves, Gregory C. Simmons, Dustin N. Sullivan, Thomas E. Summers, Jon C. Thompson, Lorenzo Wade, James S. Wheeler, Tommy N. Whitworth, and James M. Williams from the vision requirement in 49 CFR 391.41(b)(10), subject to the requirements cited above (49 CFR 391.64(b)). In accordance with 49 U.S.C. 31136(e) and 31315, each exemption will be valid for 2 years unless revoked earlier by FMCSA. The exemption will be revoked if:
(1)The person fails to comply with the terms and conditions of the exemption;
(2)the exemption has resulted in a lower level of safety than was maintained before it was granted; or
(3)continuation of the exemption would not be consistent with the goals and objectives of 49 U.S.C. 31136 and 31315. If the exemption is still effective at the end of the 2-year period, the person may apply to FMCSA for a renewal under procedures in effect at that time. Issued on: June 6, 2007. Larry W. Minor, Acting Associate Administrator, Policy and Program Development. [FR Doc. E7-11335 Filed 6-12-07; 8:45 am] BILLING CODE 4910-EX-P DEPARTMENT OF TRANSPORTATION Federal Motor Carrier Safety Administration [Docket No. FMCSA-98-4334, FMCSA-00-7006, FMCSA-00-7363, FMCSA-00-7918, FMCSA-00-8398, FMCSA-01-9258, FMCSA-03-14223, FMCSA-03-14504, FMCSA-05-20027, FMCSA-05-20560] Qualification of Drivers; Exemption Applications; Vision AGENCY: Federal Motor Carrier Safety Administration (FMCSA), DOT. ACTION: Notice of renewal of exemptions; request for comments. SUMMARY: FMCSA announces its decision to renew the exemptions from the vision requirement in the Federal Motor Carrier Safety Regulations for 31 individuals. FMCSA has statutory authority to exempt individuals from the vision requirement if the exemptions granted will not compromise safety. The Agency has concluded that granting these exemptions will provide a level of safety that will be equivalent to, or greater than, the level of safety maintained without the exemptions for these commercial motor vehicle
(CMV)drivers. DATES: This decision is effective June 26, 2007. Comments must be received on or before July 13, 2007. ADDRESSES: You may submit comments identified by DOT Docket Management System
(DMS)Docket Numbers FMCSA-98-4334, FMCSA-00-7006, FMCSA-00-7363, FMCSA-00-7918, FMCSA-00-8398, FMCSA-01-9258, FMCSA-03-14223,FMCSA-03-14504, FMCSA-05-20027, FMCSA-05-20560, using any of the following methods. • Web Site: *http://dmses.dot.gov* . Follow the instructions for submitting comments on the DOT electronic docket site. • Fax: 1-202-493-2251. • Mail: Docket Management Facility; U.S. Department of Transportation, 1200 New Jersey Avenue, SE., West Building, Ground Floor, Room W12-140, Washington, DC 20590-0001. • Hand Delivery: Room W12-140 on the ground level of the West Building, 1200 New Jersey Avenue, SE., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. • Federal eRulemaking Portal: Go to *http://www.regulations.gov* . Follow the online instructions for submitting comments. *Instructions:* All submissions must include the Agency name and docket numbers for this Notice. Note that all comments received will be posted without change to *http://dms.dot.gov* , including any personal information provided. Please see the Privacy Act heading for further information. *Docket:* For access to the docket to read background documents or comments received, go to *http://dms.dot.gov* at any time or Room W12-140 on the ground level of the West Building, 1200 New Jersey Avenue, SE., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. The DMS is available 24 hours each day, 365 days each year. If you want acknowledgment that we received your comments, please include a self-addressed, stamped envelope or postcard or print the acknowledgement page that appears after submitting comments on-line. *Privacy Act:* Anyone may search the electronic form of all comments received into any of our dockets by the name of the individual submitting the comment (or of the person signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review the Department of Transportation's complete Privacy Act Statement in the **Federal Register** published on April 11, 2000 (65 FR 19477; Apr. 11, 2000). This information is also available at *http://dms.dot.gov* . FOR FURTHER INFORMATION CONTACT: Dr. Mary D. Gunnels, Chief, Physical Qualifications Division, 202-366-4001, FMCSA, Room W64-224, U.S. Department of Transportation, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001. Office hours are from 8:30 a.m. to 5 p.m. Monday through Friday, except Federal holidays. SUPPLEMENTARY INFORMATION: Exemption Decision Under 49 U.S.C. 31136(e) and 31315, FMCSA may renew an exemption from the vision requirements in 49 CFR 391.41(b)(10), which applies to drivers of CMVs in interstate commerce, for a two-year period if it finds “such exemption would likely achieve a level of safety that is equivalent to, or greater than, the level that would be achieved absent such exemption.” The procedures for requesting an exemption (including renewals) are set out in 49 CFR part 381. This notice addresses 31 individuals who have requested renewal of their exemptions in accordance with FMCSA procedures. FMCSA has evaluated these 31 applications for renewal on their merits and decided to extend each exemption for a renewable two-year period. They are: David F. Bardsley, Sr. Gary A. Barrett Ivan L. Beal Johnny A. Beutler Daniel R. Brewer James T. Butler, Jr. Darryl D. Cassatt Brett L. Condon Mark W. Coulson Albion C. Doe John R. Hughes Daryl A. Jester Robert L. Joiner, Jr. James P. Jones Clyde H. Kitzan Larry J. Lang Dennis D. Lesperance John W. Locke Herman G. Lovell Eugene A. Maggio Ronald L. Maynard William A. Moore, Jr. Danny R. Pickelsimer Richard S. Rehbein Bernard E. Roche Darrell L. Rohlfs David E. Sanders David B. Speller Lynn D. Veach Harry S. Warren Michael C. Wines These exemptions are extended subject to the following conditions:
(1)That each individual have a physical examination every year
(a)by an ophthalmologist or optometrist who attests that the vision in the better eye continues to meet the standard in 49 CFR 391.41(b)(10), and
(b)by a medical examiner who attests that the individual is otherwise physically qualified under 49 CFR 391.41;
(2)that each individual provide a copy of the ophthalmologist's or optometrist's report to the medical examiner at the time of the annual medical examination; and
(3)that each individual provide a copy of the annual medical certification to the employer for retention in the driver's qualification file and retain a copy of the certification on his/her person while driving for presentation to a duly authorized Federal, State, or local enforcement official. Each exemption will be valid for two years unless rescinded earlier by FMCSA. The exemption will be rescinded if:
(1)The person fails to comply with the terms and conditions of the exemption;
(2)the exemption has resulted in a lower level of safety than was maintained before it was granted; or
(3)continuation of the exemption would not be consistent with the goals and objectives of 49 U.S.C. 31136(e) and 31315. Basis for Renewing Exemptions Under 49 U.S.C. 31315(b)(1), an exemption may be granted for no longer than 2 years from its approval date and may be renewed upon application for additional 2 year periods. In accordance with 49 U.S.C. 31136(e) and 31315, each of the 31 applicants has satisfied the entry conditions for obtaining an exemption from the vision requirements (63 FR 66226; 64 FR 16517; 66 FR 17994; 68 FR 15037; 70 FR 14747; 68 FR 35772; 70 FR 33937; 65 FR 20245; 65 FR 57230; 67 FR 57266; 65 FR 45817; 65 FR 77066; 65 FR 66286; 66 FR 13825; 68 FR 10300; 70 FR 7546; 65 FR 78256; 66 FR 16311; 68 FR 13360; 70 FR 12265; 66 FR 17743; 66 FR 33990; 68 FR 10301; 68 FR 19596; 70 FR 25878; 68 FR 19598; 68 FR 33570; 70 FR 2701; 70 FR 16887; 70 FR 17504; 70 FR 30997). Each of these 31 applicants has requested renewal of the exemption and has submitted evidence showing that the vision in the better eye continues to meet the standard specified at 49 CFR 391.41(b)(10) and that the vision impairment is stable. In addition, a review of each record of safety while driving with the respective vision deficiencies over the past 2 years indicates each applicant continues to meet the vision exemption standards. These factors provide an adequate basis for predicting each driver's ability to continue to drive safely in interstate commerce. Therefore, FMCSA concludes that extending the exemption for each renewal applicant for a period of two years is likely to achieve a level of safety equal to that existing without the exemption. Request for Comments FMCSA will review comments received at any time concerning a particular driver's safety record and determine if the continuation of the exemption is consistent with the requirements at 49 U.S.C. 31136(e) and 31315. However, FMCSA requests that interested parties with specific data concerning the safety records of these drivers submit comments by July 13, 2007. FMCSA believes that the requirements for a renewal of an exemption under 49 U.S.C. 31136(e) and 31315 can be satisfied by initially granting the renewal and then requesting and evaluating, if needed, subsequent comments submitted by interested parties. As indicated above, the Agency previously published notices of final disposition announcing its decision to exempt these 31 individuals from the vision requirement in 49 CFR 391.41(b)(10). The final decision to grant an exemption to each of these individuals was based on the merits of each case and only after careful consideration of the comments received to its notices of applications. The notices of applications stated in detail the qualifications, experience, and medical condition of each applicant for an exemption from the vision requirements. That information is available by consulting the above cited **Federal Register** publications. Interested parties or organizations possessing information that would otherwise show that any, or all, of these drivers, are not currently achieving the statutory level of safety should immediately notify FMCSA. The Agency will evaluate any adverse evidence submitted and, if safety is being compromised or if continuation of the exemption would not be consistent with the goals and objectives of 49 U.S.C. 31136(e) and 31315, FMCSA will take immediate steps to revoke the exemption of a driver. Issued on: June 5, 2007. Larry W. Minor, Acting Associate Administrator, Policy and Program Development. [FR Doc. E7-11337 Filed 6-12-07; 8:45 am] BILLING CODE 4910-EX-P DEPARTMENT OF TRANSPORTATION Federal Transit Administration [FTA Docket No. FTA-2007-28452] Agency Information Collection Activity Under OMB Review AGENCY: Federal Transit Administration, DOT. ACTION: Notice of request for comments. SUMMARY: The Federal Transit Administration invites public comments about our intention to request the Office of Management and Budget's
(OMB)approval to renew the following information collection: Pre-Award and Post-Delivery Review Requirements. The information to be collected for this program is necessary to certify that pre-award and post-delivery reviews will be conducted when using FTA funds to purchase revenue service vehicles. The **Federal Register** Notice with a 60-day comment period soliciting comments was published on April 3, 2007. DATES: Comments must be submitted before July 13, 2007. A comment to OMB is most effective if OMB receives it within 30 days of publication. FOR FURTHER INFORMATION CONTACT: Sylvia L. Marion, Office of Administration, Office of Management Planning,
(202)366-6680. SUPPLEMENTARY INFORMATION: *Title:* Pre-Award and Post-Delivery Review Requirements ( *OMB Number: 2132-0544* ). *Abstract:* Under the Federal Transit Laws, at 49 U.S.C. 5323(m), grantees must certify that pre-award and post-delivery reviews will be conducted when using FTA funds to purchase rolling stock and maintain on file these certifications. FTA implements this requirement in 49 CFR Part 663 by describing the certificates that must be submitted by each bidder to assure compliance with the Buy America contract specification and vehicle safety requirements for rolling stock. The information collected on the certification forms is necessary for FTA grantees to meet the requirements of 49 U.S.C. 5323(m). *Estimated Total Annual Burden:* 3,024 hours. ADDRESSES: All written comments must refer to the docket number that appears at the top of this document and be submitted to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street, NW., Washington, DC 20503, Attention: FTA Desk Officer. *Comments are Invited On:* Whether the proposed collection of information is necessary for the proper performance of the functions of the Department, including whether the information will have practical utility; the accuracy of the Department's estimate of the burden of the proposed information collection; ways to enhance the quality, utility, and clarity of the information to be collected; and ways to minimize the burden of the collection of information on respondents, including the use of automated collection techniques or other forms of information technology. Issued On: June 7, 2007. Ann M. Linnertz, Acting Associate Administrator for Administration . [FR Doc. E7-11338 Filed 6-12-07; 8:45 am] BILLING CODE 4910-57-P DEPARTMENT OF THE TREASURY Submission for OMB Review; Comment Request June 7, 2007. The Department of the Treasury has submitted the following public information collection requirement(s) to OMB for review and clearance under the Paperwork Reduction Act of 1995, Public Law 104-13. Copies of the submission(s) may be obtained by calling the Treasury Bureau Clearance Officer listed. Comments regarding this information collection should be addressed to the OMB reviewer listed and to the Treasury Department Clearance Officer, Department of the Treasury, Room 11000, 1750 Pennsylvania Avenue, NW., Washington, DC 20220. DATES: Written comments should be received on or before July 13, 2007 to be assured of consideration. Internal Revenue Service
(IRS)*OMB Number:* 1545-XXXX. *Type of Review:* New. *Title:* 990-N Electronic Notice (e-Postcard). *Form:* 990-N. *Description:* Section 1223 of the Pension Protection Act of 2006 (PPA '06), enacted on August 17, 2006, amended Internal Revenue Code
(Code)section 6033 by adding Code section 6033(i), which requires certain tax-exempt organizations to file an annual electronic notice (Form 990-N) for tax years beginning after December 31, 2006. These organizations are not required to file Form 990 (or Form 990-EZ) because their gross receipts are normally $25,000 or less. *Respondents:* Not-for-profit institutions. *Estimated Total Burden Hours:* 1,300 hours. *OMB Number:* 1545-1610. *Type of Review:* Revision. *Title:* Annual Return/Report of Employee Benefit Plan. *Form:* 5500. *Description:* Form 5500 is an annual information return filed by employee benefit plans. The IRS uses this information to determine if the plan appears to be operating properly as required under the law or whether the plan should be audited. *Respondents:* Businesses or other for-profit institutions. *Estimated Total Burden Hours:* 2,173,483 hours. *OMB Number:* 1545-2061. *Type of Review:* Revision. *Title:* Supplemental Attachment to Schedule M-3. *Form:* 8916-A. *Description:* The Form 8916-A is a detailed schedule that reconciles the amount of the cost of goods sold, interest income and interest expense reported on Schedule M-3 for the Form 1065, Form 1120, 1120-S, 1120-L, or 1120-PC. *Respondents:* Businesses or other for-profit institutions. *Estimated Total Burden Hours:* 5,049,720 hours. *OMB Number:* 1545-1287. *Type of Review:* Extension. *Title:* FI-3-91 (Final) Capitalization of Certain Policy Acquisition Expenses. *Description:* Insurance companies that enter into reinsurance agreement must determine the amounts to be capitalized under those agreements consistently. The regulations provide elections to permit companies to shift the burden of capitalization for their mutual benefit. *Respondents:* Businesses and other for-profit institutions. *Estimated Total Burden Hours:* 2,070 hours. *OMB Number:* 1545-0800. *Type of Review:* Extension. *Title:* Reg. 601.601 Rules and Regulations. *Description:* Persons wishing to speak at a public hearing on a proposed rule must submit written comments and an outline within prescribed time limits, for use in preparing agendas and allocating time. Persons interested in the issuance, amendment, or repeal or a rule may submit a petition for this. IRS considers the petitions in its deliberations. *Respondents:* Businesses, farms, and not-for-profit institutions. *Estimated Total Burden Hours:* 900 hours. *OMB Number:* 1545-0982. *Type of Review:* Extension. *Title:* LR-77-86 Temporary (TD 8124) Certain Elections Under the Tax Reform Act of 1986. *Description:* These regulations establish various elections with respect to which immediate interim guidance on the time and manner of making the election is necessary. These regulations enable taxpayers to take advantage of the benefits of various Code provisions. *Respondents:* Businesses and other for-profit institutions. *Estimated Total Burden Hours:* 28,678 hours. *OMB Number:* 1545-1443. *Type of Review:* Extension. *Title:* PS-25-94 (Final) Requirements to Ensure Collection of Section 2056A Estate Tax (TD 8686). *Description:* The regulation provides guidance relating to the additional requirements necessary to ensure the collection of the estate tax imposed under Section 2056A(b) with respect to taxable events involving qualified domestic trusts (QDOT'S). In order to ensure collection of the tax, the regulation provides various security options that may be selected by the trust and the requirements associated with each option. In addition, under certain circumstances the trust is required to file an annual statement with the IRS disclosing the assets held by the trust. *Respondents:* Individuals or households. *Estimated Total Burden Hours:* 6,070 hours. *OMB Number:* 1545-0042. *Type of Review:* Extension. *Title:* Application To Use LIFO Inventory Method. *Form:* 970. *Description:* Form 970 is filed by individuals, partnerships, trusts, estates, or corporations to elect to use the LIFO inventory method or to extend the LIFO method to additional goods. The IRS uses Form 970 to determine if the election was properly made. *Respondents:* Businesses or other for-profit institutions. *Estimated Total Burden Hours:* 24,800 hours. Clearance Officer: Glenn P. Kirkland,
(202)622-3428, Internal Revenue Service, Room 6516, 1111 Constitution Avenue, NW., Washington, DC 20224. OMB Reviewer: Alexander T. Hunt,
(202)395-7316, Office of Management and Budget, Room 10235, New Executive Office Building, Washington, DC 20503. Robert Dahl, Treasury PRA Clearance Officer. [FR Doc. E7-11493 Filed 6-12-07; 8:45 am] BILLING CODE 4830-01-P DEPARTMENT OF THE TREASURY Submission for OMB Review; Comment Request June 7, 2007. The Department of the Treasury has submitted the following public information collection requirement(s) to OMB for review and clearance under the Paperwork Reduction Act of 1995, Public Law 104-13. Copies of the submission(s) may be obtained by calling the Treasury Bureau Clearance Officer listed. Comments regarding this information collection should be addressed to the OMB reviewer listed and to the Treasury Department Clearance Officer, Department of the Treasury, Room 11000, 1750 Pennsylvania Avenue, NW., Washington, DC 20220. DATES: Written comments should be received on or before July 13, 2007 to be assured of consideration. Financial Crimes Enforcement Network (FinCEN) *OMB Number:* 1506-0003. *Type of Review:* Revision. *Title:* Imposition of Special Measure Against Commercial Bank of Syria, Including its Subsidiary, Syrian Lebanese Commercial Bank, as a Financial Institution of Primary Money Laundering Concern. *Description:* This information will be used to verify compliance by financial institutions with the requirements to notify their correspondent account holders. *Respondents:* Business and other for profit. *Estimated Total Reporting Burden:* 5,000 hours. *Clearance Officer:* Russell Stephenson,
(202)354-6012, Department of the Treasury, Financial Crimes Enforcement Network, P.O. Box 39, Vienna, VA 22183. *OMB Reviewer:* Alexander T. Hunt,
(202)395-7316, Office of Management and Budget, Room 10235, New Executive Office Building, Washington, DC 20503. Robert Dahl, Treasury PRA Clearance Officer. [FR Doc. E7-11494 Filed 6-12-07; 8:45 am] BILLING CODE 4810-02-P 72 113 Wednesday, June 13, 2007 Rules and Regulations Part II Environmental Protection Agency 40 CFR Part 60 Amendments to New Source Performance Standards
(NSPS)for Electric Utility Steam Generating Units and Industrial-Commercial-Institutional Steam Generating Units; Final Rule ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 60 [EPA-HQ-OAR-2005-0031; FRL-8302-3] RIN 2060-AN97 Standards of Performance for Fossil-Fuel-Fired Steam Generators for Which Construction Is Commenced After August 17, 1971; Standards of Performance for Electric Utility Steam Generating Units for Which Construction Is Commenced After September 18, 1978; Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units; and Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units AGENCY: Environmental Protection Agency (EPA). ACTION: Final reconsideration. SUMMARY: EPA is amending the new source performance standards
(NSPS)for electric utility steam generating units and industrial-commercial-institutional steam generating units. These amendments to the regulations are to add compliance alternatives for owners and operators of certain affected sources, revise certain recordkeeping and reporting requirements, correct technical and editorial errors, and update the grammatical style of the four subparts to be more consistent across all of the subparts. DATES: This rule is effective on June 13, 2007. The incorporation by reference of certain publications listed in these rules is approved by the Director of the Federal Register as of June 13, 2007. ADDRESSES: EPA has established a docket for this action under Docket ID No. EPA-HQ-OAR-2005-0031. All documents in the docket are listed in the Federal Docket Management System index at *http://www.regulations.gov.* Although listed in the index, some information is not publicly available, *e.g.* , confidential business information or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically through *www.regulations.gov* or in hard copy at the EPA Docket Center, Public Reading Room, EPA West, Room 3334, 1301 Constitution Ave., NW., Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is
(202)566-1744, and the telephone number for the Air Docket is
(202)566-1742. FOR FURTHER INFORMATION CONTACT: Mr. Christian Fellner, Energy Strategies Group, Sector Policies and Programs Division (D243-01), U.S. EPA, Research Triangle Park, NC 27711, telephone number
(919)541-4003, facsimile number
(919)541-5450, electronic mail (e-mail) address: *fellner.christian@epa.gov.* SUPPLEMENTARY INFORMATION: *Outline.* The information presented in this preamble is organized as follows: I. General Information A. Does this action apply to me? B. Where can I get a copy of this document? C. Judicial Review II. Background Information III. Final Amendments and Changes Since Proposal 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 Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer Advancement Act J. Congressional Review Act I. General Information A. Does this action apply to me? The regulated categories and entities potentially affected by this final action include, but are not limited to, the following: Category NAICS code 1 Examples of potentially regulated entities Industry 221112 Fossil fuel-fired electric utility steam generating units. Federal Government 22112 Fossil fuel-fired electric utility steam generating units owned by the Federal Government. State/local/tribal government 22112 Fossil fuel-fired electric utility steam generating units owned by municipalities. 921150 Fossil fuel-fired electric steam generating units in Indian Country. Any industrial, commercial, or institutional facility using a steam generating unit as defined in 60.40b or 60.40c 211 Extractors of crude petroleum and natural gas. 321 Manufacturers of lumber and wood products. 322 Pulp and paper mills. 325 Chemical manufacturers. 324 Petroleum refiners and manufacturers of coal products. 316, 326, 339 Manufacturers of rubber and miscellaneous plastic products. 331 Steel works, blast furnaces. 332 Electroplating, plating, polishing, anodizing, and coloring. 336 Manufacturers of motor vehicle parts and accessories. 221 Electric, gas, and sanitary services. 622 Health services. 611 Educational Services. 1 North American Industry Classification System (NAICS) code. This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. To determine whether your facility is regulated by this action, you should examine the applicability criteria in § 60.40a, 60.40b, or 60.40c of 40 CFR part 60. If you have any questions regarding the applicability of this action to a particular entity, consult either the air permit authority for the entity or your EPA regional representative as listed in 40 CFR 63.13 of subpart A (General Provisions). B. Where can I get a copy of this document? In addition to being available in the docket, an electronic copy of this final action will also be available on the Worldwide Web
(WWW)through the Technology Transfer Network (TTN). Following signature, a copy of this final action will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at the following address: *http://www.epa.gov/ttn/oarpg/.* The TTN provides information and technology exchange in various areas of air pollution control. C. Judicial Review Under section 307(b)(1) of the Clean Air Act (CAA), judicial review of these final rules is available only by filing a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit by August 13, 2007. Under section 307(d)(7)(B) of the CAA, only an objection to these final rules that was raised with reasonable specificity during the period for public comment can be raised during judicial review. Moreover, under section 307(b)(2) of the CAA, the requirements established by these final rules may not be challenged separately in any civil or criminal proceedings brought by EPA to enforce these requirements. II. Background Information In response to petitions for reconsideration filed by the Utility Air Regulatory Group and the Council of Industrial Boiler Owners of the amendments to the new source performance standards for steam generating units that EPA promulgated on February 27, 2006 (71 FR 9866), EPA proposed revised amendments to address issues for which the petitioners requested reconsideration (see docket entries EPA-HQ-OAR-2005-0031-0224 and EPA-HQ-OAR-2005-0031-0225). EPA proposed on February 9, 2007, (72 FR 6320) to amend 40 CFR part 60, subparts D, Da, Db, and Dc to clarify the intent for applying and implementing specific rule requirements, provide additional compliance alternatives, and to correct unintentional technical omissions and editorial errors. In addition, EPA proposed to republish 40 CFR 60.17 (Incorporations by reference) and subparts D, Da, Db, and Dc in their entirety for the purpose of revising the wording and writing style to be more consistent across all the NSPS subparts applicable to steam generating units. A 30-day comment period (February 9, 2007 to March 12, 2007) was provided to accept comments on the proposed rule. An opportunity for a public hearing was provided to allow any interested persons to present oral comments on the proposed rule. However, EPA did not receive a request for a formal public hearing, so a public hearing was not held. EPA did receive a request for a 15-day extension to the comment period. EPA granted an extension of the public comment period to March 26, 2007 (72 FR 9903, March 6, 2007). We received comments on the proposed amendments from 20 commenters during the comment period. III. Final Amendments and Changes Since Proposal We are amending 40 CFR part 60, subparts D, Da, Db, and Dc to add compliance alternatives for owners and operators of certain affected sources, revise certain recordkeeping and reporting requirements, correct technical and editorial errors, and update the grammatical style of the four subparts to be more consistent across all of the subparts. This action promulgates the proposed regulatory language for the amendments except for those significant provisions, as noted below, for which modifications were made to the regulatory language for the final amendments in response to specific public comments. EPA did not receive negative comments on the conforming changes to the regulatory text and is, therefore, finalizing all those changes. The final amendments promulgated by this action reflect EPA's consideration of the comments received on the proposal. EPA's responses to the substantive public comments on the proposal are presented in a comment summary and response document available in Docket ID No. EPA-HQ-OAR-2005-0031. The requirements in subpart Da for demonstrating continuous compliance with the particulate matter
(PM)emission limits for affected electric utility steam generating units that commence construction, reconstruction, or modification after February 28, 2005, have been revised since proposal in response to comments. EPA is retaining the provision, established in the February 27, 2006 final rule, allowing the optional use of PM continuous emission monitoring systems
(CEMS)to steam generating units for demonstration of compliance with rule requirements related to controlling PM emissions. Owners and operators choosing to install and properly operate PM CEMS must demonstrate compliance with the applicable PM emission limit on a daily basis and are not required to install a continuous opacity monitoring system
(COMS)or to monitor PM control device performance. We recognize that experience using PM CEMS at electric utility power plants in the United States is limited, and not all affected owners and operators will choose to use PM CEMS. Therefore, the final amendments allow owners and operators of affected electric utility steam generating units constructed, reconstructed, or modified after February 28, 2005, to demonstrate compliance with the PM emissions limit using periodic PM emissions performance testing and continuous monitoring of the PM control device performance using one of two alternatives. The first monitoring alternative is for an owner or operator of an affected source to monitor PM control device performance based on the opacity level measured during the stack performance test conducted to demonstrate compliance with the applicable PM emissions limit. The second alternative available to owners and operators depends on the type of PM control device used for the electric utility steam generating unit. The owner or operator of an affected source that uses an electrostatic precipitator
(ESP)can elect to monitor performance of the control device using an ESP predictive emissions model. An owner or operator of an affected source that uses a fabric filter can elect to monitor control device performance using a bag leak detection system. One significant change from the proposal is that owners or operators of affected source that use parametric monitoring of PM emissions will have a grace period to bring the monitoring parameters back into the range established during the most recent PM emissions performance test prior to the requirement to conduct a new PM emissions performance test. The grace period does not apply to the 6-minute opacity standard and owners and operators of affected sources must continue to report excess 6-minute opacity measurements. EPA has finalized several other alternatives to provide owners and operators of affected electric utility steam generating units additional flexibility in complying with the NSPS. EPA has finalized the optional use of Part 75 NO <sup>X</sup> and SO <sup>2</sup> CEMS calibration procedures to satisfy Part 60 requirements as proposed, the amendments to § 60.13 providing a standard methodology for validating partial operating hours, and the amendments to Appendix B of Part 60 allowing the calibration drift test be conducted over 7 consecutive operating days instead of 7 consecutive calendar days and the relative accuracy test audit flexibility (as described in docket entry EPA-HQ-OAR-2005-0031-0234). In addition, EPA has finalized the option for steam generating units subject to subpart D allowing affected owners and operators to choose as an alternative to complying with the applicable NO <sup>X</sup> and SO <sup>2</sup> emission limits in the rule to comply with the 30-day average NO <sup>X</sup> and SO <sup>2</sup> standards for modified sources in subparts Da and Db, as applicable to the affected source. For industrial/commercial/institutional steam generating units subject to subpart Db and burning coke oven gas (COG), we have expanded the applicability of the 30-day annual exemption from the SO <sup>2</sup> emissions limit to all units subject to subpart Db that burn COG. The amendments to subpart Db promulgated in February 27, 2006, added this flexibility for those steam generating units constructed, reconstructed, or modified after February 28, 2005, to account for byproduct plant maintenance. Based on comments we received, the amendments promulgated by this action provide the same compliance flexibility to the owner or operator of any COG-fired steam generating unit subject to subpart Db. The final amendments add to subparts D, Da, Db, and Dc monitoring alternatives to existing requirements to use COMS for owners and operators of steam generating units burning gaseous fuels or low sulfur fuel oils. Owners and operators of electric utility steam generating units subject to subpart D or Da may elect to use a carbon monoxide
(CO)CEMS in place of the COMS. Owners and operators of industrial/commercial/institutional steam generating units subject to subpart Db or Dc may elect to either use a CO CEMS or to operate according to a site-specific monitoring plan in place of using a COMS. Finally, minor revisions to the proposed regulatory language were made to clarify specific provisions or to correct unintentional technical omissions and terminology, typographical, printing, and grammatical errors that were identified in the proposed rule. These changes include revising appropriate definitions and requirements in subpart Da to clarify the applicability and implementation of the subpart Da provisions to integrated coal gasification combined cycle electric utility power plants. IV. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review This action is not a “significant regulatory action” under the terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is, therefore, not subject to review under the Executive Order. EPA has concluded that the amendments EPA is promulgating will not change the costs or benefits of the rule. B. Paperwork Reduction Act This action does not impose any new information collection burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 *et seq.* The final amendments result in no changes to the information collection requirements of the existing standards of performance and would have no impact on the information collection estimate of projected cost and hour burden made and approved by the Office of Management and Budget
(OMB)during the development of the existing standards of performance. Therefore, the information collection requests have not been amended. OMB has previously approved the information collection requirements contained in the existing standards of performance (40 CFR part 60, subparts D, Da, Db, and Dc) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 *et seq.* , at the time the standards were promulgated on June 11, 1979 (40 CFR part 60, subpart Da, 44 FR 33580), November 25, 1986 (40 CFR part 60, subpart Db, 51 FR 42768), and September 12, 1990 (40 CFR part 60, subpart Dc, 55 FR 37674). OMB assigned OMB control numbers 2060-0023 (ICR 1053.08) for 40 CFR part 60, subpart Da; 2060-0072 (ICR 1088.11) for 40 CFR part 60, subpart Db; 2060-0202 (ICR 1564.06) for 40 CFR part 60, subpart Dc. Copies of the information collection request document(s) may be obtained from Susan Auby, Collection Strategies Division, U.S. EPA (2822T), 1200 Pennsylvania Ave., NW., Washington, DC 20460, by e-mail at *auby.susan@epa.gov* , or by calling
(202)566-1672. 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. 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 Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of the final amendments on small entities, small entity is defined as:
(1)A small business as defined by the Small Business Administration's regulations at 13 CFR 121.201;
(2)a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; 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 this final rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. Although this action will not have a significant economic impact on a substantial number of small entities, EPA nonetheless has tried to reduce the impact of this rule on small entities. EPA is reducing the fuel usage recordkeeping requirement for subpart Dc facilities. In addition, EPA is minimizing the continuous opacity monitoring requirements for certain oil-fired facilities. EPA has, therefore, concluded that this action will relieve regulatory burden for the majority of affected small entities. EPA continues to be interested in the potential impacts of the rule on small entities and welcomes 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 to State, local, and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any one year. Before promulgating an EPA rule for which a written statement is needed, section 205 of the UMRA generally requires EPA to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost-effective or least burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are inconsistent with applicable law. Moreover, section 205 allows EPA to adopt an alternative other than the least costly, most cost-effective or least burdensome alternative if the Administrator publishes with the final rule an explanation why that alternative was not adopted. Before EPA establishes any regulatory requirements that may significantly or uniquely affect small governments, including tribal governments, it must have developed under section 203 of the UMRA a small government agency plan. The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of EPA regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements. EPA has determined that the final amendments will contain no Federal mandates 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. Thus, the final amendments are not subject to the requirements of section 202 and 205 of the UMRA. In addition, EPA has determined that the final amendments contain no regulatory requirements that might significantly or uniquely affect small governments because the burden is small and the regulation does not unfairly apply to small governments. Therefore, the final amendments are not subject to the requirements of 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.” The final amendments do not have federalism implications. They will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. The final amendments will not impose substantial direct compliance costs on State or local governments; it will not preempt State law. Thus, Executive Order 13132 does not apply to the final amendments. 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.” The final amendments do not have tribal implications, as specified in Executive Order 13175. While utility steam generating units are located on tribal lands EPA is not aware of any that are tribally owned. To the extend that institutional steam generating units are tribally owned the final amendments will not have substantial direct effects on tribal governments, on the relationship between the Federal government and Indian tribes, or on the distribution of power and responsibilities between the Federal government and Indian tribes. Thus, Executive Order 13175 does not apply to the final amendments. G. Executive Order 13045: Protection of Children From Environmental Health and Safety Risks Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any rule that:
(1)Is determined to be “economically significant” as defined under Executive Order 12866, and
(2)concerns an environmental health or safety risk that EPA has reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria, the Agency must evaluate the environmental health or safety effects of the planned rule on children, and explain why the planned regulation is preferable to other potentially effective and reasonably feasible alternatives considered by the Agency. This action is not subject to the Executive Order because it is not economically significant as defined under Executive Order 12866, and because EPA interprets Executive Order 13045 as applying only to those regulatory actions that are based on health or safety risks, such that the analysis required under section 5-501 of the Order has the potential to influence the regulation. The final amendments are based on technology performance and not on health or safety risks and, therefore, are not subject to Executive Order 13045. H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use The final amendments are not a “significant energy action”: As defined in Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001) because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy because it only clarifies our intent and corrects errors in the existing rule. Further, we have concluded that the final amendments are not likely to have any adverse energy effects. I. National Technology Transfer Advancement Act Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law 104-113, Section 12(d)(15 U.S.C. 272 note) directs us to use voluntary consensus standards in our regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards ( *e.g.* , material specifications, test methods, sampling procedures, business practices) developed or adopted by one or more voluntary consensus bodies. The NTTAA directs us to provide Congress, through OMB, explanations when we decide not use available and applicable voluntary consensus standards. This action does not involve any new technical standards or the incorporation by reference of existing technical standards. Therefore, the consideration of voluntary consensus standards is not relevant to this action. J. Congressional Review Act The Congressional Review Act, 5 U.S.C. 801, *et seq.* , as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of Congress and to the Comptroller General of the United States. EPA will submit a report containing these final amendments and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication of the final rules in the **Federal Register** . A major rule cannot take effect until 60 days after it is published in the **Federal Register** . This action is not a “major rule” as defined by 5 U.S.C. 804(2). These final amendments will be effective on June 13, 2007. List of Subjects in 40 CFR Part 60 Environmental protection, Administrative practice and procedure, Air pollution control, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements. Dated: April 13, 2007. Stephen L. Johnson, Administrator. For the reasons stated in the preamble, title 40, chapter I, part 60, of the Code of the Federal Regulations is amended as follows: PART 60—[AMENDED] 1. The authority citation for part 60 continues to read as follows: Authority: 42 U.S.C. 7401, *et seq.* Subpart A—[Amended] 2. Section 60.13 is amended by revising paragraph
(h)to read as follows: § 60.13 Monitoring requirements. (h)(1) Owners or operators of all continuous monitoring systems for measurement of opacity shall reduce all data to 6-minute averages and for continuous monitoring systems other than opacity to 1-hour averages for time periods as defined in § 60.2. Six-minute opacity averages shall be calculated from 36 or more data points equally spaced over each 6-minute period.
(2)For continuous monitoring systems other than opacity, 1-hour averages shall be computed as follows, except that the provisions pertaining to the validation of partial operating hours are only applicable for affected facilities that are required by the applicable subpart to include partial hours in the emission calculations:
(i)Except as provided under paragraph (h)(2)(iii) of this section, for a full operating hour (any clock hour with 60 minutes of unit operation), at least four valid data points are required to calculate the hourly average, *i.e.* , one data point in each of the 15-minute quadrants of the hour.
(ii)Except as provided under paragraph (h)(2)(iii) of this section, for a partial operating hour (any clock hour with less than 60 minutes of unit operation), at least one valid data point in each 15-minute quadrant of the hour in which the unit operates is required to calculate the hourly average.
(iii)For any operating hour in which required maintenance or quality-assurance activities are performed:
(A)If the unit operates in two or more quadrants of the hour, a minimum of two valid data points, separated by at least 15 minutes, is required to calculate the hourly average; or
(B)If the unit operates in only one quadrant of the hour, at least one valid data point is required to calculate the hourly average.
(iv)If a daily calibration error check is failed during any operating hour, all data for that hour shall be invalidated, unless a subsequent calibration error test is passed in the same hour and the requirements of paragraph (h)(2)(iii) of this section are met, based solely on valid data recorded after the successful calibration.
(v)For each full or partial operating hour, all valid data points shall be used to calculate the hourly average.
(vi)Except as provided under paragraph (h)(2)(vii) of this section, data recorded during periods of continuous monitoring system breakdown, repair, calibration checks, and zero and span adjustments shall not be included in the data averages computed under this paragraph.
(vii)Owners and operators complying with the requirements of § 60.7(f)(1) or
(2)must include any data recorded during periods of monitor breakdown or malfunction in the data averages.
(viii)When specified in an applicable subpart, hourly averages for certain partial operating hours shall not be computed or included in the emission averages ( *e.g.* hours with < 30 minutes of unit operation under § 60.47b(d)).
(ix)Either arithmetic or integrated averaging of all data may be used to calculate the hourly averages. The data may be recorded in reduced or nonreduced form ( *e.g.* , ppm pollutant and percent O <sup>2</sup> or ng/J of pollutant).
(3)All excess emissions shall be converted into units of the standard using the applicable conversion procedures specified in the applicable subpart. After conversion into units of the standard, the data may be rounded to the same number of significant digits used in the applicable subpart to specify the emission limit. § 60.17 [Amended] 3. Section 60.17 is amended by revising paragraphs
(a)and (h)(2) to read as follows:
(a)The following materials are available for purchase from at least one of the following addresses: American Society for Testing and Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West Conshohocken, PA 19428-2959; or ProQuest, 300 North Zeeb Road, Ann Arbor, MI 48106.
(1)ASTM A99-76, 82 (Reapproved 1987), Standard Specification for Ferromanganese, incorporation by reference
(IBR)approved for § 60.261.
(2)ASTM A100-69, 74, 93, Standard Specification for Ferrosilicon, IBR approved for § 60.261.
(3)ASTM A101-73, 93, Standard Specification for Ferrochromium, IBR approved for § 60.261.
(4)ASTM A482-76, 93, Standard Specification for Ferrochromesilicon, IBR approved for § 60.261.
(5)ASTM A483-64, 74 (Reapproved 1988), Standard Specification for Silicomanganese, IBR approved for § 60.261.
(6)ASTM A495-76, 94, Standard Specification for Calcium-Silicon and Calcium Manganese-Silicon, IBR approved for § 60.261.
(7)ASTM D86-78, 82, 90, 93, 95, 96, Distillation of Petroleum Products, IBR approved for §§ 60.562-2(d), 60.593(d), and 60.633(h).
(8)ASTM D129-64, 78, 95, 00, Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), IBR approved for §§ 60.106(j)(2), 60.335(b)(10)(i), and Appendix A: Method 19, 12.5.2.2.3.
(9)ASTM D129-00 (Reapproved 2005), Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), IBR approved for § 60.4415(a)(1)(i).
(10)ASTM D240-76, 92, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for §§ 60.46(c), 60.296(b), and Appendix A: Method 19, Section 12.5.2.2.3.
(11)ASTM D270-65, 75, Standard Method of Sampling Petroleum and Petroleum Products, IBR approved for Appendix A: Method 19, Section 12.5.2.2.1.
(12)ASTM D323-82, 94, Test Method for Vapor Pressure of Petroleum Products (Reid Method), IBR approved for §§ 60.111(l), 60.111a(g), 60.111b(g), and 60.116b(f)(2)(ii).
(13)ASTM D388-77, 90, 91, 95, 98a, 99 (Reapproved 2004) ε 1 , Standard Specification for Classification of Coals by Rank, IBR approved for §§ 60.24(h)(8), 60.41 of subpart D of this part, 60.45(f)(4)(i), 60.45(f)(4)(ii), 60.45(f)(4)(vi), 60.41Da of subpart Da of this part, 60.41b of subpart Db of this part, 60.41c of subpart Dc of this part, and 60.4102.
(14)ASTM D388-77, 90, 91, 95, 98a, Standard Specification for Classification of Coals by Rank, IBR approved for §§ 60.251(b) and
(c)of subpart Y of this part.
(15)ASTM D396-78, 89, 90, 92, 96, 98, Standard Specification for Fuel Oils, IBR approved for §§ 60.41b of subpart Db of this part, 60.41c of subpart Dc of this part, 60.111(b) of subpart K of this part, and 60.111a(b) of subpart Ka of this part.
(16)ASTM D975-78, 96, 98a, Standard Specification for Diesel Fuel Oils, IBR approved for §§ 60.111(b) of subpart K of this part and 60.111a(b) of subpart Ka of this part.
(17)ASTM D1072-80, 90 (Reapproved 1994), Standard Test Method for Total Sulfur in Fuel Gases, IBR approved for § 60.335(b)(10)(ii).
(18)ASTM D1072-90 (Reapproved 1999), Standard Test Method for Total Sulfur in Fuel Gases, IBR approved for § 60.4415(a)(1)(ii).
(19)ASTM D1137-53, 75, Standard Method for Analysis of Natural Gases and Related Types of Gaseous Mixtures by the Mass Spectrometer, IBR approved for § 60.45(f)(5)(i).
(20)ASTM D1193-77, 91, Standard Specification for Reagent Water, IBR approved for Appendix A: Method 5, Section 7.1.3; Method 5E, Section 7.2.1; Method 5F, Section 7.2.1; Method 6, Section 7.1.1; Method 7, Section 7.1.1; Method 7C, Section 7.1.1; Method 7D, Section 7.1.1; Method 10A, Section 7.1.1; Method 11, Section 7.1.3; Method 12, Section 7.1.3; Method 13A, Section 7.1.2; Method 26, Section 7.1.2; Method 26A, Section 7.1.2; and Method 29, Section 7.2.2.
(21)ASTM D1266-87, 91, 98, Standard Test Method for Sulfur in Petroleum Products (Lamp Method), IBR approved for §§ 60.106(j)(2) and 60.335(b)(10)(i).
(22)ASTM D1266-98 (Reapproved 2003)e1, Standard Test Method for Sulfur in Petroleum Products (Lamp Method), IBR approved for § 60.4415(a)(1)(i).
(23)ASTM D1475-60 (Reapproved 1980), 90, Standard Test Method for Density of Paint, Varnish Lacquer, and Related Products, IBR approved for § 60.435(d)(1), Appendix A: Method 24, Section 6.1; and Method 24A, Sections 6.5 and 7.1.
(24)ASTM D1552-83, 95, 01, Standard Test Method for Sulfur in Petroleum Products (High-Temperature Method), IBR approved for §§ 60.106(j)(2), 60.335(b)(10)(i), and Appendix A: Method 19, Section 12.5.2.2.3.
(25)ASTM D1552-03, Standard Test Method for Sulfur in Petroleum Products (High-Temperature Method), IBR approved for § 60.4415(a)(1)(i).
(26)ASTM D1826-77, 94, Standard Test Method for Calorific Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR approved for §§ 60.45(f)(5)(ii), 60.46(c)(2), 60.296(b)(3), and Appendix A: Method 19, Section 12.3.2.4.
(27)ASTM D1835-87, 91, 97, 03a, Standard Specification for Liquefied Petroleum
(LP)Gases, IBR approved for §§ 60.41Da of subpart Da of this part, 60.41b of subpart Db of this part, and 60.41c of subpart Dc of this part.
(28)ASTM D1945-64, 76, 91, 96, Standard Method for Analysis of Natural Gas by Gas Chromatography, IBR approved for § 60.45(f)(5)(i).
(29)ASTM D1946-77, 90 (Reapproved 1994), Standard Method for Analysis of Reformed Gas by Gas Chromatography, IBR approved for §§ 60.18(f)(3), 60.45(f)(5)(i), 60.564(f)(1), 60.614(e)(2)(ii), 60.614(e)(4), 60.664(e)(2)(ii), 60.664(e)(4), 60.704(d)(2)(ii), and 60.704(d)(4).
(30)ASTM D2013-72, 86, Standard Method of Preparing Coal Samples for Analysis, IBR approved for Appendix A: Method 19, Section 12.5.2.1.3.
(31)ASTM D2015-77 (Reapproved 1978), 96, Standard Test Method for Gross Calorific Value of Solid Fuel by the Adiabatic Bomb Calorimeter, IBR approved for § 60.45(f)(5)(ii), 60.46(c)(2), and Appendix A: Method 19, Section 12.5.2.1.3.
(32)ASTM D2016-74, 83, Standard Test Methods for Moisture Content of Wood, IBR approved for Appendix A: Method 28, Section 16.1.1.
(33)ASTM D2234-76, 96, 97b, 98, Standard Methods for Collection of a Gross Sample of Coal, IBR approved for Appendix A: Method 19, Section 12.5.2.1.1.
(34)ASTM D2369-81, 87, 90, 92, 93, 95, Standard Test Method for Volatile Content of Coatings, IBR approved for Appendix A: Method 24, Section 6.2.
(35)ASTM D2382-76, 88, Heat of Combustion of Hydrocarbon Fuels by Bomb Calorimeter (High-Precision Method), IBR approved for §§ 60.18(f)(3), 60.485(g)(6), 60.564(f)(3), 60.614(e)(4), 60.664(e)(4), and 60.704(d)(4).
(36)ASTM D2504-67, 77, 88 (Reapproved 1993), Noncondensable Gases in C3 and Lighter Hydrocarbon Products by Gas Chromatography, IBR approved for § 60.485(g)(5).
(37)ASTM D2584-68 (Reapproved 1985), 94, Standard Test Method for Ignition Loss of Cured Reinforced Resins, IBR approved for § 60.685(c)(3)(i).
(38)ASTM D2597-94 (Reapproved 1999), Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for § 60.335(b)(9)(i).
(39)ASTM D2622-87, 94, 98, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR approved for §§ 60.106(j)(2) and 60.335(b)(10)(i).
(40)ASTM D2622-05, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR approved for § 60.4415(a)(1)(i).
(41)ASTM D2879-83, 96, 97, Test Method for Vapor Pressure-Temperature Relationship and Initial Decomposition Temperature of Liquids by Isoteniscope, IBR approved for §§ 60.111b(f)(3), 60.116b(e)(3)(ii), 60.116b(f)(2)(i), and 60.485(e)(1).
(42)ASTM D2880-78, 96, Standard Specification for Gas Turbine Fuel Oils, IBR approved for §§ 60.111(b), 60.111a(b), and 60.335(d).
(43)ASTM D2908-74, 91, Standard Practice for Measuring Volatile Organic Matter in Water by Aqueous-Injection Gas Chromatography, IBR approved for § 60.564(j).
(44)ASTM D2986-71, 78, 95a, Standard Method for Evaluation of Air, Assay Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR approved for Appendix A: Method 5, Section 7.1.1; Method 12, Section 7.1.1; and Method 13A, Section 7.1.1.2.
(45)ASTM D3173-73, 87, Standard Test Method for Moisture in the Analysis Sample of Coal and Coke, IBR approved for Appendix A: Method 19, Section 12.5.2.1.3.
(46)ASTM D3176-74, 89, Standard Method for Ultimate Analysis of Coal and Coke, IBR approved for § 60.45(f)(5)(i) and Appendix A: Method 19, Section 12.3.2.3.
(47)ASTM D3177-75, 89, Standard Test Method for Total Sulfur in the Analysis Sample of Coal and Coke, IBR approved for Appendix A: Method 19, Section 12.5.2.1.3.
(48)ASTM D3178-73 (Reapproved 1979), 89, Standard Test Methods for Carbon and Hydrogen in the Analysis Sample of Coal and Coke, IBR approved for § 60.45(f)(5)(i).
(49)ASTM D3246-81, 92, 96, Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry, IBR approved for § 60.335(b)(10)(ii).
(50)ASTM D3246-05, Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry, IBR approved for § 60.4415(a)(1)(ii).
(51)ASTM D3270-73T, 80, 91, 95, Standard Test Methods for Analysis for Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated Method), IBR approved for Appendix A: Method 13A, Section 16.1.
(52)ASTM D3286-85, 96, Standard Test Method for Gross Calorific Value of Coal and Coke by the Isoperibol Bomb Calorimeter, IBR approved for Appendix A: Method 19, Section 12.5.2.1.3.
(53)ASTM D3370-76, 95a, Standard Practices for Sampling Water, IBR approved for § 60.564(j).
(54)ASTM D3792-79, 91, Standard Test Method for Water Content of Water-Reducible Paints by Direct Injection into a Gas Chromatograph, IBR approved for Appendix A: Method 24, Section 6.3.
(55)ASTM D4017-81, 90, 96a, Standard Test Method for Water in Paints and Paint Materials by the Karl Fischer Titration Method, IBR approved for Appendix A: Method 24, Section 6.4.
(56)ASTM D4057-81, 95, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, IBR approved for Appendix A: Method 19, Section 12.5.2.2.3.
(57)ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual Sampling of Petroleum and Petroleum Products, IBR approved for § 60.4415(a)(1).
(58)ASTM D4084-82, 94, Standard Test Method for Analysis of Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR approved for § 60.334(h)(1).
(59)ASTM D4084-05, Standard Test Method for Analysis of Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR approved for §§ 60.4360 and 60.4415(a)(1)(ii).
(60)ASTM D4177-95, Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, IBR approved for Appendix A: Method 19, Section 12.5.2.2.1.
(61)ASTM D4177-95 (Reapproved 2000), Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, IBR approved for § 60.4415(a)(1).
(62)ASTM D4239-85, 94, 97, Standard Test Methods for Sulfur in the Analysis Sample of Coal and Coke Using High Temperature Tube Furnace Combustion Methods, IBR approved for Appendix A: Method 19, Section 12.5.2.1.3.
(63)ASTM D4294-02, Standard Test Method for Sulfur in Petroleum and Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectrometry, IBR approved for § 60.335(b)(10)(i).
(64)ASTM D4294-03, Standard Test Method for Sulfur in Petroleum and Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectrometry, IBR approved for § 60.4415(a)(1)(i).
(65)ASTM D4442-84, 92, Standard Test Methods for Direct Moisture Content Measurement in Wood and Wood-base Materials, IBR approved for Appendix A: Method 28, Section 16.1.1.
(66)ASTM D4444-92, Standard Test Methods for Use and Calibration of Hand-Held Moisture Meters, IBR approved for Appendix A: Method 28, Section 16.1.1.
(67)ASTM D4457-85 (Reapproved 1991), Test Method for Determination of Dichloromethane and 1, 1, 1-Trichloroethane in Paints and Coatings by Direct Injection into a Gas Chromatograph, IBR approved for Appendix A: Method 24, Section 6.5.
(68)ASTM D4468-85 (Reapproved 2000), Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry, IBR approved for §§ 60.335(b)(10)(ii) and 60.4415(a)(1)(ii).
(69)ASTM D4629-02, Standard Test Method for Trace Nitrogen in Liquid Petroleum Hydrocarbons by Syringe/Inlet Oxidative Combustion and Chemiluminescence Detection, IBR approved for §§ 60.49b(e) and 60.335(b)(9)(i).
(70)ASTM D4809-95, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR approved for §§ 60.18(f)(3), 60.485(g)(6), 60.564(f)(3), 60.614(d)(4), 60.664(e)(4), and 60.704(d)(4).
(71)ASTM D4810-88 (Reapproved 1999), Standard Test Method for Hydrogen Sulfide in Natural Gas Using Length of Stain Detector Tubes, IBR approved for §§ 60.4360 and 60.4415(a)(1)(ii).
(72)ASTM D5287-97 (Reapproved 2002), Standard Practice for Automatic Sampling of Gaseous Fuels, IBR approved for § 60.4415(a)(1).
(73)ASTM D5403-93, Standard Test Methods for Volatile Content of Radiation Curable Materials, IBR approved for Appendix A: Method 24, Section 6.6.
(74)ASTM D5453-00, Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet Fluorescence, IBR approved for § 60.335(b)(10)(i).
(75)ASTM D5453-05, Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet Fluorescence, IBR approved for § 60.4415(a)(1)(i).
(76)ASTM D5504-01, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence, IBR approved for §§ 60.334(h)(1) and 60.4360.
(77)ASTM D5762-02, Standard Test Method for Nitrogen in Petroleum and Petroleum Products by Boat-Inlet Chemiluminescence, IBR approved for § 60.335(b)(9)(i).
(78)ASTM D5865-98, Standard Test Method for Gross Calorific Value of Coal and Coke, IBR approved for § 60.45(f)(5)(ii), 60.46(c)(2), and Appendix A: Method 19, Section 12.5.2.1.3.
(79)ASTM D6216-98, Standard Practice for Opacity Monitor Manufacturers to Certify Conformance with Design and Performance Specifications, IBR approved for Appendix B, Performance Specification 1.
(80)ASTM D6228-98, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Flame Photometric Detection, IBR approved for § 60.334(h)(1).
(81)ASTM D6228-98 (Reapproved 2003), Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Flame Photometric Detection, IBR approved for §§ 60.4360 and 60.4415.
(82)ASTM D6348-03, Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared
(FTIR)Spectroscopy, IBR approved for table 7 of Subpart IIII of this part.
(83)ASTM D6366-99, Standard Test Method for Total Trace Nitrogen and Its Derivatives in Liquid Aromatic Hydrocarbons by Oxidative Combustion and Electrochemical Detection, IBR approved for § 60.335(b)(9)(i).
(84)ASTM D6522-00, Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers, IBR approved for § 60.335(a).
(85)ASTM D6667-01, Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence, IBR approved for § 60.335(b)(10)(ii).
(86)ASTM D6667-04, Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence, IBR approved for § 60.4415(a)(1)(ii).
(87)ASTM D6784-02, Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method), IBR approved for Appendix B to part 60, Performance Specification 12A, Section 8.6.2.
(88)ASTM E168-67, 77, 92, General Techniques of Infrared Quantitative Analysis, IBR approved for §§ 60.593(b)(2) and 60.632(f).
(89)ASTM E169-63, 77, 93, General Techniques of Ultraviolet Quantitative Analysis, IBR approved for §§ 60.593(b)(2) and 60.632(f).
(90)ASTM E260-73, 91, 96, General Gas Chromatography Procedures, IBR approved for §§ 60.593(b)(2) and 60.632(f).
(h)* * *
(2)ASME PTC 4.1-1964 (Reaffirmed 1991), Power Test Codes: Test Code for Steam Generating Units (with 1968 and 1969 Addenda), IBR approved for §§ 60.46b of subpart Db of this part, 60.58a(h)(6)(ii), 60.58b(i)(6)(ii), 60.1320(a)(3) and 60.1810(a)(3). Subpart D—[Amended] 4. Part 60 is amended by revising subpart D to read as follows: Subpart D—Standards of Performance for Fossil-Fuel-Fired Steam Generators for Which Construction Is Commenced After August 17, 1971 Sec. 60.40 Applicability and designation of affected facility. 60.41 Definitions. 60.42 Standard for particulate matter (PM). 60.43 Standard for sulfur dioxide (SO <sup>2</sup> ). 60.44 Standard for nitrogen oxides (NO <sup>X</sup> ). 60.45 Emission and fuel monitoring. 60.46 Test methods and procedures. Subpart D—Standards of Performance for Fossil-Fuel-Fired Steam Generators for Which Construction Is Commenced After August 17, 1971 § 60.40 Applicability and designation of affected facility.
(a)The affected facilities to which the provisions of this subpart apply are:
(1)Each fossil-fuel-fired steam generating unit of more than 73 megawatts
(MW)heat input rate (250 million British thermal units per hour (MMBtu/hr)).
(2)Each fossil-fuel and wood-residue-fired steam generating unit capable of firing fossil fuel at a heat input rate of more than 73 MW (250 MMBtu/hr).
(b)Any change to an existing fossil-fuel-fired steam generating unit to accommodate the use of combustible materials, other than fossil fuels as defined in this subpart, shall not bring that unit under the applicability of this subpart.
(c)Except as provided in paragraph
(d)of this section, any facility under paragraph
(a)of this section that commenced construction or modification after August 17, 1971, is subject to the requirements of this subpart.
(d)The requirements of §§ 60.44 (a)(4), (a)(5),
(b)and (d), and 60.45(f)(4)(vi) are applicable to lignite-fired steam generating units that commenced construction or modification after December 22, 1976.
(e)Any facility covered under subpart Da is not covered under this subpart. § 60.41 Definitions. As used in this subpart, all terms not defined herein shall have the meaning given them in the Act, and in subpart A of this part. *Boiler operating day* means a 24-hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the steam-generating unit. It is not necessary for fuel to be combusted the entire 24-hour period. *Coal* means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by ASTM D388 (incorporated by reference, see § 60.17). *Coal refuse* means waste-products of coal mining, cleaning, and coal preparation operations (e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material. *Fossil fuel* means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such materials for the purpose of creating useful heat. *Fossil fuel and wood residue-fired steam generating unit* means a furnace or boiler used in the process of burning fossil fuel and wood residue for the purpose of producing steam by heat transfer. *Fossil-fuel-fired steam generating unit* means a furnace or boiler used in the process of burning fossil fuel for the purpose of producing steam by heat transfer. *Wood residue* means bark, sawdust, slabs, chips, shavings, mill trim, and other wood products derived from wood processing and forest management operations. § 60.42 Standard for particulate matter (PM).
(a)On and after the date on which the performance test required to be conducted by § 60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases that:
(1)Contain PM in excess of 43 nanograms per joule (ng/J) heat input (0.10 lb/MMBtu) derived from fossil fuel or fossil fuel and wood residue.
(2)Exhibit greater than 20 percent opacity except for one six-minute period per hour of not more than 27 percent opacity. (b)(1) On or after December 28, 1979, no owner or operator shall cause to be discharged into the atmosphere from the Southwestern Public Service Company's Harrington Station #1, in Amarillo, TX, any gases which exhibit greater than 35 percent opacity, except that a maximum or 42 percent opacity shall be permitted for not more than 6 minutes in any hour.
(2)Interstate Power Company shall not cause to be discharged into the atmosphere from its Lansing Station Unit No. 4 in Lansing, IA, any gases which exhibit greater than 32 percent opacity, except that a maximum of 39 percent opacity shall be permitted for not more than six minutes in any hour. § 60.43 Standard for sulfur dioxide (SO <sup>2</sup> ).
(a)Except as provided under paragraph
(d)of this section, on and after the date on which the performance test required to be conducted by § 60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases that contain SO <sup>2</sup> in excess of:
(1)340 ng/J heat input (0.80 lb/MMBtu) derived from liquid fossil fuel or liquid fossil fuel and wood residue.
(2)520 ng/J heat input (1.2 lb/MMBtu) derived from solid fossil fuel or solid fossil fuel and wood residue, except as provided in paragraph
(e)of this section.
(b)Except as provided under paragraph
(d)of this section, when different fossil fuels are burned simultaneously in any combination, the applicable standard (in ng/J) shall be determined by proration using the following formula: ER13JN07.000 Where: PS <sup>SO</sup> 2 = Prorated standard for S <sup>O2</sup> when burning different fuels simultaneously, in ng/J heat input derived from all fossil fuels or from all fossil fuels and wood residue fired; y = Percentage of total heat input derived from liquid fossil fuel; and z = Percentage of total heat input derived from solid fossil fuel.
(c)Compliance shall be based on the total heat input from all fossil fuels burned, including gaseous fuels.
(d)As an alternate to meeting the requirements of paragraphs
(a)and
(b)of this section, an owner or operator can petition the Administrator (in writing) to comply with § 60.43Da(i)(3) of subpart Da of this part or comply with § 60.42b(k) of subpart Db of this part, as applicable to the affected source. If the Administrator grants the petition, the source will from then on (unless the unit is modified or reconstructed in the future) have to comply with the requirements in § 60.43Da(i)(3) of subpart Da of this part or § 60.42b(k) of subpart Db of this part, as applicable to the affected source.
(e)Units 1 and 2 (as defined in appendix G of this part) at the Newton Power Station owned or operated by the Central Illinois Public Service Company will be in compliance with paragraph (a)(2) of this section if Unit 1 and Unit 2 individually comply with paragraph (a)(2) of this section or if the combined emission rate from Units 1 and 2 does not exceed 470 ng/J (1.1 lb/MMBtu) combined heat input to Units 1 and 2. § 60.44 Standard for nitrogen oxides (NO X ).
(a)Except as provided under paragraph
(e)of this section, on and after the date on which the performance test required to be conducted by § 60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases that contain NO <sup>X</sup> , expressed as NO <sup>2</sup> in excess of:
(1)86 ng/J heat input (0.20 lb/MMBtu) derived from gaseous fossil fuel.
(2)129 ng/J heat input (0.30 lb/MMBtu) derived from liquid fossil fuel, liquid fossil fuel and wood residue, or gaseous fossil fuel and wood residue.
(3)300 ng/J heat input (0.70 lb/MMBtu) derived from solid fossil fuel or solid fossil fuel and wood residue (except lignite or a solid fossil fuel containing 25 percent, by weight, or more of coal refuse).
(4)260 ng/J heat input (0.60 lb MMBtu) derived from lignite or lignite and wood residue (except as provided under paragraph (a)(5) of this section).
(5)340 ng/J heat input (0.80 lb MMBtu) derived from lignite which is mined in North Dakota, South Dakota, or Montana and which is burned in a cyclone-fired unit.
(b)Except as provided under paragraphs (c), (d), and
(e)of this section, when different fossil fuels are burned simultaneously in any combination, the applicable standard (in ng/J) is determined by proration using the following formula: ER13JN07.001 Where: PS <sup>NO</sup> <sup>x</sup> = Prorated standard for NO <sup>X</sup> when burning different fuels simultaneously, in ng/J heat input derived from all fossil fuels fired or from all fossil fuels and wood residue fired; w = Percentage of total heat input derived from lignite; x = Percentage of total heat input derived from gaseous fossil fuel; y = Percentage of total heat input derived from liquid fossil fuel; and z = Percentage of total heat input derived from solid fossil fuel (except lignite).
(c)When a fossil fuel containing at least 25 percent, by weight, of coal refuse is burned in combination with gaseous, liquid, or other solid fossil fuel or wood residue, the standard for NO <sup>X</sup> does not apply.
(d)Except as provided under paragraph
(e)of this section, cyclone-fired units which burn fuels containing at least 25 percent of lignite that is mined in North Dakota, South Dakota, or Montana remain subject to paragraph (a)(5) of this section regardless of the types of fuel combusted in combination with that lignite.
(e)As an alternate to meeting the requirements of paragraphs (a), (b), and
(d)of this section, an owner or operator can petition the Administrator (in writing) to comply with § 60.44Da(e)(3) of subpart Da of this part. If the Administrator grants the petition, the source will from then on (unless the unit is modified or reconstructed in the future) have to comply with the requirements in § 60.44Da(e)(3) of subpart Da of this part. § 60.45 Emissions and fuel monitoring.
(a)Each owner or operator shall install, calibrate, maintain, and operate continuous emissions monitoring systems
(CEMS)for measuring the opacity of emissions, SO <sup>2</sup> emissions, NO <sup>X</sup> emissions, and either oxygen (O <sup>2</sup> ) or carbon dioxide (CO <sup>2</sup> ) except as provided in paragraph
(b)of this section.
(b)Certain of the CEMS requirements under paragraph
(a)of this section do not apply to owners or operators under the following conditions:
(1)For a fossil-fuel-fired steam generator that burns only gaseous fossil fuel and that does not use post-combustion technology to reduce emissions of SO <sup>2</sup> or PM, CEMS for measuring the opacity of emissions and SO <sup>2</sup> emissions are not required.
(2)For a fossil-fuel-fired steam generator that does not use a flue gas desulfurization device, a CEMS for measuring SO <sup>2</sup> emissions is not required if the owner or operator monitors SO <sup>2</sup> emissions by fuel sampling and analysis.
(3)Notwithstanding § 60.13(b), installation of a CEMS for NO <sup>X</sup> may be delayed until after the initial performance tests under § 60.8 have been conducted. If the owner or operator demonstrates during the performance test that emissions of NO <sup>X</sup> are less than 70 percent of the applicable standards in § 60.44, a CEMS for measuring NO <sup>X</sup> emissions is not required. If the initial performance test results show that NO <sup>X</sup> emissions are greater than 70 percent of the applicable standard, the owner or operator shall install a CEMS for NO <sup>X</sup> within one year after the date of the initial performance tests under § 60.8 and comply with all other applicable monitoring requirements under this part.
(4)If an owner or operator does not install any CEMS for sulfur oxides and NO <sup>X</sup> , as provided under paragraphs (b)(1) and (b)(3) or paragraphs (b)(2) and (b)(3) of this section a CEMS for measuring either O <sup>2</sup> or CO <sup>2</sup> is not required.
(5)An owner or operator may petition the Administrator (in writing) to install a PM CEMS as an alternative to the CEMS for monitoring opacity emissions.
(6)A CEMS for measuring the opacity of emissions is not required for a fossil fuel-fired steam generator that does not use post-combustion technology (except a wet scrubber) for reducing PM, SO <sup>2</sup> , or carbon monoxide
(CO)emissions, burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 weight percent sulfur, and is operated such that emissions of CO to the atmosphere from the affected source are maintained at levels less than or equal to 0.15 lb/MMBtu on a boiler operating day average basis. Owners and operators of affected sources electing to comply with this paragraph must demonstrate compliance according to the procedures specified in paragraphs (b)(6)(i) through
(iv)of this section.
(i)You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs (b)(6)(i)(A) through
(D)of this section.
(A)The CO CEMS must be installed, certified, maintained, and operated according to the provisions in § 60.58b(i)(3) of subpart Eb of this part.
(B)Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis).
(C)At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-day rolling average basis. At least two data points per hour must be used to calculate each 1-hour average.
(D)Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be performed in accordance with procedure 1 in appendix F of this part.
(ii)You must calculate the 1-hour average CO emissions levels for each boiler operating day by multiplying the average hourly CO output concentration measured by the CO CEMS times the corresponding average hourly flue gas flow rate and divided by the corresponding average hourly heat input to the affected source. The 24-hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission levels computed for each boiler operating day.
(iii)You must evaluate the preceding 24-hour average CO emission level each boiler operating day excluding periods of affected source startup, shutdown, or malfunction. If the 24-hour average CO emission level is greater than 0.15 lb/MMBtu, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of the high emission incident and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 0.15 lb/MMBtu or less.
(iv)You must record the CO measurements and calculations performed according to paragraph (b)(6) of this section and any corrective actions taken. The record of corrective action taken must include the date and time during which the 24-hour average CO emission level was greater than 0.15 lb/MMBtu, and the date, time, and description of the corrective action.
(c)For performance evaluations under § 60.13(c) and calibration checks under § 60.13(d), the following procedures shall be used:
(1)Methods 6, 7, and 3B of appendix A of this part, as applicable, shall be used for the performance evaluations of SO <sup>2</sup> and NO <sup>X</sup> continuous monitoring systems. Acceptable alternative methods for Methods 6, 7, and 3B of appendix A of this part are given in § 60.46(d).
(2)Sulfur dioxide or nitric oxide, as applicable, shall be used for preparing calibration gas mixtures under Performance Specification 2 of appendix B to this part.
(3)For affected facilities burning fossil fuel(s), the span value for a continuous monitoring system measuring the opacity of emissions shall be 80, 90, or 100 percent. For a continuous monitoring system measuring sulfur oxides or NO <sup>X</sup> the span value shall be determined using one of the following procedures:
(i)Except as provided under paragraph (c)(3)(ii) of this section, SO <sup>2</sup> and NO <sup>X</sup> span values shall be determined as follows: Fossil fuel In parts per million Span value for SO <sup>2</sup> Span value for NO <sup>X</sup> Gas ( 1 ) 500. Liquid 1,000 500. Solid 1,500 1,000. Combinations 1,000y + 1,500z 500 (x + y) + 1,000z. 1 Not applicable. Where: x = Fraction of total heat input derived from gaseous fossil fuel; y = Fraction of total heat input derived from liquid fossil fuel; and z = Fraction of total heat input derived from solid fossil fuel.
(ii)As an alternative to meeting the requirements of paragraph (c)(3)(i) of this section, the owner or operator of an affected facility may elect to use the SO <sup>2</sup> and NO <sup>X</sup> span values determined according to sections 2.1.1 and 2.1.2 in appendix A to part 75 of this chapter.
(4)All span values computed under paragraph (c)(3)(i) of this section for burning combinations of fossil fuels shall be rounded to the nearest 500 ppm. Span values that are computed under paragraph (c)(3)(ii) of this section shall be rounded off according to the applicable procedures in section 2 of appendix A to part 75 of this chapter.
(5)For a fossil-fuel-fired steam generator that simultaneously burns fossil fuel and nonfossil fuel, the span value of all CEMS shall be subject to the Administrator's approval.
(d)[Reserved]
(e)For any CEMS installed under paragraph
(a)of this section, the following conversion procedures shall be used to convert the continuous monitoring data into units of the applicable standards (ng/J, lb/MMBtu):
(1)When a CEMS for measuring O <sup>2</sup> is selected, the measurement of the pollutant concentration and O <sup>2</sup> concentration shall each be on a consistent basis (wet or dry). Alternative procedures approved by the Administrator shall be used when measurements are on a wet basis. When measurements are on a dry basis, the following conversion procedure shall be used: ER13JN07.002 Where E, C, F, and %O <sup>2</sup> are determined under paragraph
(f)of this section.
(2)When a CEMS for measuring CO <sup>2</sup> is selected, the measurement of the pollutant concentration and CO <sup>2</sup> concentration shall each be on a consistent basis (wet or dry) and the following conversion procedure shall be used: ER13JN07.003 Where E, C, F <sup>c</sup> and %CO <sup>2</sup> are determined under paragraph
(f)of this section.
(f)The values used in the equations under paragraphs (e)(1) and
(2)of this section are derived as follows:
(1)E = pollutant emissions, ng/J (lb/MMBtu).
(2)C = pollutant concentration, ng/dscm (lb/dscf), determined by multiplying the average concentration
(ppm)for each one-hour period by 4.15 × 10 4 M ng/dscm per ppm (2.59 × 10 −9 M lb/dscf per ppm) where M = pollutant molecular weight, g/g-mole (lb/lb-mole). M = 64.07 for SO <sup>2</sup> and 46.01 for NO <sup>X</sup> .
(3)%O <sup>2</sup> , %CO <sup>2</sup> = O <sup>2</sup> or CO <sup>2</sup> volume (expressed as percent), determined with equipment specified under paragraph
(a)of this section.
(4)F, F <sup>c</sup> = a factor representing a ratio of the volume of dry flue gases generated to the calorific value of the fuel combusted (F), and a factor representing a ratio of the volume of CO <sup>2</sup> generated to the calorific value of the fuel combusted (F <sup>c</sup> ), respectively. Values of F and F <sup>c</sup> are given as follows:
(i)For anthracite coal as classified according to ASTM D388 (incorporated by reference, see § 60.17), F = 2,723 × 10 −17 dscm/J (10,140 dscf/MMBtu) and F <sup>c</sup> = 0.532 × 10 −17 scm CO <sup>2</sup> /J (1,980 scf CO <sup>2</sup> /MMBtu).
(ii)For subbituminous and bituminous coal as classified according to ASTM D388 (incorporated by reference, see § 60.17), F = 2.637 × 10 −7 dscm/J (9,820 dscf/MMBtu) and F <sup>c</sup> = 0.486 × 10 −7 scm CO <sup>2</sup> /J (1,810 scf CO <sup>2</sup> /MMBtu).
(iii)For liquid fossil fuels including crude, residual, and distillate oils, F = 2.476 × 10 −7 dscm/J (9,220 dscf/MMBtu) and F <sup>c</sup> = 0.384 × 10 −7 scm CO <sup>2</sup> /J (1,430 scf CO <sup>2</sup> /MMBtu).
(iv)For gaseous fossil fuels, F = 2.347 × 10 −7 dscm/J (8,740 dscf/MMBtu). For natural gas, propane, and butane fuels, F <sup>c</sup> = 0.279 × 10 −7 scm CO <sup>2</sup> /J (1,040 scf CO <sup>2</sup> /MMBtu) for natural gas, 0.322 × 10 −7 scm CO <sup>2</sup> /J (1,200 scf CO <sup>2</sup> /MMBtu) for propane, and 0.338 × 10 −7 scm CO <sup>2</sup> /J (1,260 scf CO <sup>2</sup> /MMBtu) for butane.
(v)For bark F = 2.589 × 10 −7 dscm/J (9,640 dscf/MMBtu) and F <sup>c</sup> = 0.500 × 10 −7 scm CO <sup>2</sup> /J (1,840 scf CO <sup>2</sup> /MMBtu). For wood residue other than bark F = 2.492 × 10 −7 dscm/J (9,280 dscf/MMBtu) and F <sup>c</sup> = 0.494 × 10 −7 scm CO <sup>2</sup> /J (1,860 scf CO <sup>2</sup> /MMBtu).
(vi)For lignite coal as classified according to ASTM D388 (incorporated by reference, see § 60.17), F = 2.659 × 10 −7 dscm/J (9,900 dscf/MMBtu) and F <sup>c</sup> = 0.516 × 10 −7 scm CO <sup>2</sup> /J (1,920 scf CO <sup>2</sup> /MMBtu).
(5)The owner or operator may use the following equation to determine an F factor (dscm/J or dscf/MMBtu) on a dry basis (if it is desired to calculate F on a wet basis, consult the Administrator) or Fc factor (scm CO <sup>2</sup> /J, or scf CO <sup>2</sup> /MMBtu) on either basis in lieu of the F or F <sup>c</sup> factors specified in paragraph (f)(4) of this section: ER13JN07.004
(i)%H, %C, %S, %N, and %O are content by weight of hydrogen, carbon, sulfur, nitrogen, and O <sup>2</sup> (expressed as percent), respectively, as determined on the same basis as GCV by ultimate analysis of the fuel fired, using ASTM D3178 or D3176 (solid fuels), or computed from results using ASTM D1137, D1945, or D1946 (gaseous fuels) as applicable. (These five methods are incorporated by reference, see § 60.17.)
(ii)GVC is the gross calorific value (kJ/kg, Btu/lb) of the fuel combusted determined by the ASTM test methods D2015 or D5865 for solid fuels and D1826 for gaseous fuels as applicable. (These three methods are incorporated by reference, see § 60.17.)
(iii)For affected facilities which fire both fossil fuels and nonfossil fuels, the F or Fc value shall be subject to the Administrator's approval.
(6)For affected facilities firing combinations of fossil fuels or fossil fuels and wood residue, the F or Fc factors determined by paragraphs (f)(4) or (f)(5) of this section shall be prorated in accordance with the applicable formula as follows: ER13JN07.005 Where: X <sup>i</sup> = Fraction of total heat input derived from each type of fuel (e.g. natural gas, bituminous coal, wood residue, etc.); F <sup>i</sup> or (F <sup>c</sup> ) <sup>i</sup> = Applicable F or F <sup>c</sup> factor for each fuel type determined in accordance with paragraphs (f)(4) and (f)(5) of this section; and n = Number of fuels being burned in combination.
(g)Excess emission and monitoring system performance reports shall be submitted to the Administrator semiannually for each six-month period in the calendar year. All semiannual reports shall be postmarked by the 30th day following the end of each six-month period. Each excess emission and MSP report shall include the information required in § 60.7(c). Periods of excess emissions and monitoring systems
(MS)downtime that shall be reported are defined as follows:
(1)*Opacity* . Excess emissions are defined as any six-minute period during which the average opacity of emissions exceeds 20 percent opacity, except that one six-minute average per hour of up to 27 percent opacity need not be reported.
(i)For sources subject to the opacity standard of § 60.42(b)(1), excess emissions are defined as any six-minute period during which the average opacity of emissions exceeds 35 percent opacity, except that one six-minute average per hour of up to 42 percent opacity need not be reported.
(ii)For sources subject to the opacity standard of § 60.42(b)(2), excess emissions are defined as any six-minute period during which the average opacity of emissions exceeds 32 percent opacity, except that one six-minute average per hour of up to 39 percent opacity need not be reported.
(2)*Sulfur dioxide* . Excess emissions for affected facilities are defined as:
(i)Any three-hour period during which the average emissions (arithmetic average of three contiguous one-hour periods) of SO <sup>2</sup> as measured by a CEMS exceed the applicable standard under § 60.43, or
(ii)Any 30 operating day period during which the average emissions (arithmetic average of all one-hour periods during the 30 operating days) of SO <sup>2</sup> as measured by a CEMS exceed the applicable standard under § 60.43. Facilities complying with the 30-day SO <sup>2</sup> standard shall use the most current associated SO <sup>2</sup> compliance and monitoring requirements in §§ 60.48Da and 60.49Da of subpart Da of this part.
(3)*Nitrogen oxides* . Excess emissions for affected facilities using a CEMS for measuring NO <sup>X</sup> are defined as:
(i)Any three-hour period during which the average emissions (arithmetic average of three contiguous one-hour periods) exceed the applicable standards under § 60.44, or
(ii)Any 30 operating day period during which the average emissions (arithmetic average of all one-hour periods during the 30 operating days) of NO <sup>X</sup> as measured by a CEMS exceed the applicable standard under § 60.43. Facilities complying with the 30-day NO <sup>X</sup> standard shall use the most current associated NO <sup>X</sup> compliance and monitoring requirements in §§ 60.48Da and 60.49Da of subpart Da of this part.
(4)*Particulate matter* . Excess emissions for affected facilities using a CEMS for measuring PM are defined as any boiler operating day period during which the average emissions (arithmetic average of all operating one-hour periods) exceed the applicable standards under § 60.43. Affected facilities using PM CEMS in lieu of a CEMS for monitoring opacity emissions must follow the most current applicable compliance and monitoring provisions in §§ 60.48Da and 60.49Da of subpart Da of this part. § 60.46 Test methods and procedures.
(a)In conducting the performance tests required in § 60.8, and subsequent performance tests as requested by the EPA Administrator, the owner or operator shall use as reference methods and procedures the test methods in appendix A of this part or other methods and procedures as specified in this section, except as provided in § 60.8(b). Acceptable alternative methods and procedures are given in paragraph
(d)of this section.
(b)The owner or operator shall determine compliance with the PM, SO <sup>2</sup> , and NO <sup>X</sup> standards in §§ 60.42, 60.43, and 60.44 as follows:
(1)The emission rate
(E)of PM, SO <sup>2</sup> , or NO <sup>X</sup> shall be computed for each run using the following equation: ER13JN07.006 Where: E = Emission rate of pollutant, ng/J (1b/million Btu); C = Concentration of pollutant, ng/dscm (1b/dscf); %O <sup>2</sup> = O <sup>2</sup> concentration, percent dry basis; and F <sup>d</sup> = Factor as determined from Method 19 of appendix A of this part.
(2)Method 5 of appendix A of this part shall be used to determine the PM concentration
(C)at affected facilities without wet flue-gas-desulfurization
(FGD)systems and Method 5B of appendix A of this part shall be used to determine the PM concentration
(C)after FGD systems.
(i)The sampling time and sample volume for each run shall be at least 60 minutes and 0.85 dscm (30 dscf). The probe and filter holder heating systems in the sampling train shall be set to provide an average gas temperature of 160±14 °C (320±25 °F).
(ii)The emission rate correction factor, integrated or grab sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O <sup>2</sup> concentration (%O <sup>2</sup> ). The O <sup>2</sup> sample shall be obtained simultaneously with, and at the same traverse points as, the particulate sample. If the grab sampling procedure is used, the O <sup>2</sup> concentration for the run shall be the arithmetic mean of the sample O <sup>2</sup> concentrations at all traverse points.
(iii)If the particulate run has more than 12 traverse points, the O <sup>2</sup> traverse points may be reduced to 12 provided that Method 1 of appendix A of this part is used to locate the 12 O <sup>2</sup> traverse points.
(3)Method 9 of appendix A of this part and the procedures in § 60.11 shall be used to determine opacity.
(4)Method 6 of appendix A of this part shall be used to determine the SO <sup>2</sup> concentration.
(i)The sampling site shall be the same as that selected for the particulate sample. The sampling location in the duct shall be at the centroid of the cross section or at a point no closer to the walls than 1 m (3.28 ft). The sampling time and sample volume for each sample run shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Two samples shall be taken during a 1-hour period, with each sample taken within a 30-minute interval.
(ii)The emission rate correction factor, integrated sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O <sup>2</sup> concentration (%O <sup>2</sup> ). The O <sup>2</sup> sample shall be taken simultaneously with, and at the same point as, the SO <sup>2</sup> sample. The SO <sup>2</sup> emission rate shall be computed for each pair of SO <sup>2</sup> and O <sup>2</sup> samples. The SO <sup>2</sup> emission rate
(E)for each run shall be the arithmetic mean of the results of the two pairs of samples.
(5)Method 7 of appendix A of this part shall be used to determine the NO <sup>X</sup> concentration.
(i)The sampling site and location shall be the same as for the SO <sup>2</sup> sample. Each run shall consist of four grab samples, with each sample taken at about 15-minute intervals.
(ii)For each NO <sup>X</sup> sample, the emission rate correction factor, grab sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O <sup>2</sup> concentration (%O <sup>2</sup> ). The sample shall be taken simultaneously with, and at the same point as, the NO <sup>X</sup> sample.
(iii)The NO <sup>X</sup> emission rate shall be computed for each pair of NO <sup>X</sup> and O <sup>2</sup> samples. The NO <sup>X</sup> emission rate
(E)for each run shall be the arithmetic mean of the results of the four pairs of samples.
(c)When combinations of fossil fuels or fossil fuel and wood residue are fired, the owner or operator (in order to compute the prorated standard as shown in §§ 60.43(b) and 60.44(b)) shall determine the percentage (w, x, y, or z) of the total heat input derived from each type of fuel as follows:
(1)The heat input rate of each fuel shall be determined by multiplying the gross calorific value of each fuel fired by the rate of each fuel burned.
(2)ASTM Methods D2015, or D5865 (solid fuels), D240 (liquid fuels), or D1826 (gaseous fuels) (all of these methods are incorporated by reference, see § 60.17) shall be used to determine the gross calorific values of the fuels. The method used to determine the calorific value of wood residue must be approved by the Administrator.
(3)Suitable methods shall be used to determine the rate of each fuel burned during each test period, and a material balance over the steam generating system shall be used to confirm the rate.
(d)The owner or operator may use the following as alternatives to the reference methods and procedures in this section or in other sections as specified:
(1)The emission rate
(E)of PM, SO <sup>2</sup> and NO <sup>X</sup> may be determined by using the Fc factor, provided that the following procedure is used:
(i)The emission rate
(E)shall be computed using the following equation: ER13JN07.007 Where: E = Emission rate of pollutant, ng/J (lb/MMBtu); C = Concentration of pollutant, ng/dscm (lb/dscf); %CO <sup>2</sup> = CO <sup>2</sup> concentration, percent dry basis; and F <sup>c</sup> = Factor as determined in appropriate sections of Method 19 of appendix A of this part.
(ii)If and only if the average Fc factor in Method 19 of appendix A of this part is used to calculate E and either E is from 0.97 to 1.00 of the emission standard or the relative accuracy of a continuous emission monitoring system is from 17 to 20 percent, then three runs of Method 3B of appendix A of this part shall be used to determine the O <sup>2</sup> and CO <sup>2</sup> concentration according to the procedures in paragraph (b)(2)(ii), (4)(ii), or (5)(ii) of this section. Then if F <sup>o</sup> (average of three runs), as calculated from the equation in Method 3B of appendix A of this part, is more than ±3 percent than the average F <sup>o</sup> value, as determined from the average values of F <sup>d</sup> and F <sup>c</sup> in Method 19 of appendix A of this part, *i.e.* , F <sup>oa</sup> = 0.209 (F <sup>da</sup> /F <sup>ca</sup> ), then the following procedure shall be followed:
(A)When F <sup>o</sup> is less than 0.97 F <sup>oa</sup> , then E shall be increased by that proportion under 0.97 F <sup>oa</sup> , *e.g.* , if F <sup>o</sup> is 0.95 F <sup>oa</sup> , E shall be increased by 2 percent. This recalculated value shall be used to determine compliance with the emission standard.
(B)When F <sup>o</sup> is less than 0.97 F <sup>oa</sup> and when the average difference
(d)between the continuous monitor minus the reference methods is negative, then E shall be increased by that proportion under 0.97 F <sup>oa</sup> , *e.g.* , if F <sup>o</sup> is 0.95 F <sup>oa</sup> , E shall be increased by 2 percent. This recalculated value shall be used to determine compliance with the relative accuracy specification.
(C)When F <sup>o</sup> is greater than 1.03 F <sup>oa</sup> and when the average difference d is positive, then E shall be decreased by that proportion over 1.03 F <sup>oa</sup> , *e.g.* , if F <sup>o</sup> is 1.05 F <sup>oa</sup> , E shall be decreased by 2 percent. This recalculated value shall be used to determine compliance with the relative accuracy specification.
(2)For Method 5 or 5B of appendix A of this part, Method 17 of appendix A of this part may be used at facilities with or without wet FGD systems if the stack gas temperature at the sampling location does not exceed an average temperature of 16 0°C (320 °F). The procedures of sections 2.1 and 2.3 of Method 5B of appendix A of this part may be used with Method 17 of appendix A of this part only if it is used after wet FGD systems. Method 17 of appendix A of this part shall not be used after wet FGD systems if the effluent gas is saturated or laden with water droplets.
(3)Particulate matter and SO <sup>2</sup> may be determined simultaneously with the Method 5 of appendix A of this part train provided that the following changes are made:
(i)The filter and impinger apparatus in sections 2.1.5 and 2.1.6 of Method 8 of appendix A of this part is used in place of the condenser (section 2.1.7) of Method 5 of appendix A of this part.
(ii)All applicable procedures in Method 8 of appendix A of this part for the determination of SO <sup>2</sup> (including moisture) are used:
(4)For Method 6 of appendix A of this part, Method 6C of appendix A of this part may be used. Method 6A of appendix A of this part may also be used whenever Methods 6 and 3B of appendix A of this part data are specified to determine the SO <sup>2</sup> emission rate, under the conditions in paragraph (d)(1) of this section.
(5)For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or 7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of appendix A of this part is used, the sampling time for each run shall be at least 1 hour and the integrated sampling approach shall be used to determine the O <sup>2</sup> concentration (%O <sup>2</sup> ) for the emission rate correction factor.
(6)For Method 3 of appendix A of this part, Method 3A or 3B of appendix A of this part may be used.
(7)For Method 3B of appendix A of this part, Method 3A of appendix A of this part may be used. Subpart Da—[Amended] 4a. Subpart Da is revised as follows: Subpart Da—Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978 Sec. 60.40Da Applicability and designation of affected facility. 60.41Da Definitions. 60.42Da Standard for particulate matter (PM). 60.43Da Standard for sulfur dioxide (SO <sup>2</sup> ). 60.44Da Standard for nitrogen oxides (NO <sup>X</sup> ). 60.45Da Standard for mercury (Hg). 60.46Da [Reserved] 60.47Da Commercial demonstration permit. 60.48Da Compliance provisions. 60.49Da Emission monitoring. 60.50Da Compliance determination procedures and methods. 60.51Da Reporting requirements. 60.52Da Recordkeeping requirements. Subpart Da—Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978 § 60.40Da Applicability and designation of affected facility.
(a)The affected facility to which this subpart applies is each electric utility steam generating unit:
(1)That is capable of combusting more than 73 megawatts
(MW)(250 million British thermal units per hour (MMBtu/hr) heat input of fossil fuel (either alone or in combination with any other fuel); and
(2)For which construction, modification, or reconstruction is commenced after September 18, 1978.
(b)Combined cycle gas turbines (both the stationary combustion turbine and any associated duct burners) are subject to this part and not subject to subpart GG or KKKK of this part if:
(1)The combined cycle gas turbine is capable of combusting more than 73 MW (250 MMBtu/hr) heat input of fossil fuel (either alone or in combination with any other fuel); and
(2)The combined cycle gas turbine is designed and intended to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas on a 12-month rolling average basis; and
(3)The combined cycle gas turbine commenced construction, modification, or reconstruction after February 28, 2005.
(4)This subpart will continue to apply to all other electric utility combined cycle gas turbines that are capable of combusting more than 73 MW (250 MMBtu/hr) heat input of fossil fuel in the heat recovery steam generator. If the heat recovery steam generator is subject to this subpart and the stationary combustion turbine is subject to either subpart GG or KKKK of this part, only emissions resulting from combustion of fuels in the steam-generating unit are subject to this subpart. (The stationary combustion turbine emissions are subject to subpart GG or KKKK, as applicable, of this part).
(c)Any change to an existing fossil-fuel-fired steam generating unit to accommodate the use of combustible materials, other than fossil fuels, shall not bring that unit under the applicability of this subpart.
(d)Any change to an existing steam generating unit originally designed to fire gaseous or liquid fossil fuels, to accommodate the use of any other fuel (fossil or nonfossil) shall not bring that unit under the applicability of this subpart. § 60.41Da Definitions. As used in this subpart, all terms not defined herein shall have the meaning given them in the Act and in subpart A of this part. *Anthracite* means coal that is classified as anthracite according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17). *Available purchase power* means the lesser of the following:
(a)The sum of available system capacity in all neighboring companies.
(b)The sum of the rated capacities of the power interconnection devices between the principal company and all neighboring companies, minus the sum of the electric power load on these interconnections.
(c)The rated capacity of the power transmission lines between the power interconnection devices and the electric generating units (the unit in the principal company that has the malfunctioning flue gas desulfurization system and the unit(s) in the neighboring company supplying replacement electrical power) less the electric power load on these transmission lines. *Available system capacity means* the capacity determined by subtracting the system load and the system emergency reserves from the net system capacity. *Biomass* means plant materials and animal waste. *Bituminous coal* means coal that is classified as bituminous according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17). *Boiler operating day* for units constructed, reconstructed, or modified on or before February 28, 2005, means a 24-hour period during which fossil fuel is combusted in a steam-generating unit for the entire 24 hours. For units constructed, reconstructed, or modified after February 28, 2005, *boiler operating day* means a 24-hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the steam-generating unit. It is not necessary for fuel to be combusted the entire 24-hour period. *Coal* means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17) and coal refuse. Synthetic fuels derived from coal for the purpose of creating useful heat, including but not limited to solvent-refined coal, gasified coal (not meeting the definition of natural gas), coal-oil mixtures, and coal-water mixtures are included in this definition for the purposes of this subpart. *Coal-fired electric utility steam generating* *unit* means an electric utility steam generating unit that burns coal, coal refuse, or a synthetic gas derived from coal either exclusively, in any combination together, or in any combination with other fuels in any amount. *Coal refuse* means waste products of coal mining, physical coal cleaning, and coal preparation operations ( *e.g.* culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material. *Cogeneration, also known as “combined heat and power,”* means a steam-generating unit that simultaneously produces both electric (or mechanical) and useful thermal energy from the same primary energy source. *Combined cycle gas turbine* means a stationary turbine combustion system where heat from the turbine exhaust gases is recovered by a steam generating unit. *Dry flue gas desulfurization technology* or *dry FGD* means a sulfur dioxide control system that is located downstream of the steam generating unit and removes sulfur oxides (SO <sup>2</sup> ) from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline reagent and water, whether introduced separately or as a premixed slurry or solution and forming a dry powder material. This definition includes devices where the dry powder material is subsequently converted to another form. Alkaline slurries or solutions used in dry FGD technology include, but are not limited to, lime and sodium. *Duct burner* means a device that combusts fuel and that is placed in the exhaust duct from another source, such as a stationary gas turbine, internal combustion engine, kiln, etc., to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a heat recovery steam generating unit. *Electric utility combined cycle gas turbine* means any combined cycle gas turbine used for electric generation that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW net-electrical output to any utility power distribution system for sale. Any steam distribution system that is constructed for the purpose of providing steam to a steam electric generator that would produce electrical power for sale is also considered in determining the electrical energy output capacity of the affected facility. *Electric utility company* means the largest interconnected organization, business, or governmental entity that generates electric power for sale ( *e.g.* , a holding company with operating subsidiary companies). *Electric utility steam-generating unit* means any steam electric generating unit that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW net-electrical output to any utility power distribution system for sale. Also, any steam supplied to a steam distribution system for the purpose of providing steam to a steam-electric generator that would produce electrical energy for sale is considered in determining the electrical energy output capacity of the affected facility. *Electrostatic precipitator* or *ESP* means an add-on air pollution control device used to capture particulate matter
(PM)by charging the particles using an electrostatic field, collecting the particles using a grounded collecting surface, and transporting the particles into a hopper. *Emergency condition* means that period of time when:
(1)The electric generation output of an affected facility with a malfunctioning flue gas desulfurization system cannot be reduced or electrical output must be increased because:
(i)All available system capacity in the principal company interconnected with the affected facility is being operated, and
(ii)All available purchase power interconnected with the affected facility is being obtained, or
(2)The electric generation demand is being shifted as quickly as possible from an affected facility with a malfunctioning flue gas desulfurization system to one or more electrical generating units held in reserve by the principal company or by a neighboring company, or
(3)An affected facility with a malfunctioning flue gas desulfurization system becomes the only available unit to maintain a part or all of the principal company's system emergency reserves and the unit is operated in spinning reserve at the lowest practical electric generation load consistent with not causing significant physical damage to the unit. If the unit is operated at a higher load to meet load demand, an emergency condition would not exist unless the conditions under paragraph
(1)of this definition apply. *Emission limitation* means any emissions limit or operating limit. *Emission rate period* means any calendar month included in a 12-month rolling average period. *Federally enforceable* means all limitations and conditions that are enforceable by the Administrator, including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State implementation plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 51.24. *Fossil fuel* means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat. *Gaseous fuel* means any fuel derived from coal or petroleum that is present as a gas at standard conditions and includes, but is not limited to, refinery fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal. *Gross output* means the gross useful work performed by the steam generated and, for an IGCC electric utility steam generating unit, the fuel burned in stationary combustion turbines. For a unit generating only electricity, the gross useful work performed is the gross electrical output from the unit's turbine/generator sets. For a cogeneration unit, the gross useful work performed is the gross electrical or mechanical output plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output (i.e., steam delivered to an industrial process). *24-hour period* means the period of time between 12:01 a.m. and 12:00 midnight. *Integrated gasification combined cycle electric utility steam generating unit* or *IGCC electric utility steam generating unit* means a coal-fired electric utility steam generating unit that burns a synthetic gas derived from coal in a combined-cycle gas turbine. No coal is directly burned in the unit during operation. *Interconnected* means that two or more electric generating units are electrically tied together by a network of power transmission lines, and other power transmission equipment. *ISO conditions* means a temperature of 288 Kelvin, a relative humidity of 60 percent, and a pressure of 101.3 kilopascals. *Lignite* means coal that is classified as lignite A or B according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17). *Natural gas* means:
(1)A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal constituent is methane; or
(2)Liquid petroleum gas, as defined by the American Society of Testing and Materials in ASTM D1835 (incorporated by reference, see § 60.17); or
(3)A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value between 34 and 43 megajoules
(MJ)per standard cubic meter (910 and 1,150 Btu per standard cubic foot). *Neighboring company* means any one of those electric utility companies with one or more electric power interconnections to the principal company and which have geographically adjoining service areas. *Net-electric output* means the gross electric sales to the utility power distribution system minus purchased power on a calendar year basis. *Net system capacity* means the sum of the net electric generating capability (not necessarily equal to rated capacity) of all electric generating equipment owned by an electric utility company (including steam generating units, internal combustion engines, gas turbines, nuclear units, hydroelectric units, and all other electric generating equipment) plus firm contractual purchases that are interconnected to the affected facility that has the malfunctioning flue gas desulfurization system. The electric generating capability of equipment under multiple ownership is prorated based on ownership unless the proportional entitlement to electric output is otherwise established by contractual arrangement. *Noncontinental area* means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern Mariana Islands. *Petroleum* means crude oil or petroleum or a fuel derived from crude oil or petroleum, including, but not limited to, distillate oil, residual oil, and petroleum coke. *Potential combustion concentration* means the theoretical emissions (nanograms per joule (ng/J), lb/MMBtu heat input) that would result from combustion of a fuel in an uncleaned state without emission control systems) and:
(1)For particulate matter
(PM)is:
(i)3,000 ng/J (7.0 lb/MMBtu) heat input for solid fuel; and
(ii)73 ng/J (0.17 lb/MMBtu) heat input for liquid fuels.
(2)For sulfur dioxide (SO <sup>2</sup> ) is determined under § 60.50Da(c).
(3)For nitrogen oxides (NO <sup>X</sup> ) is:
(i)290 ng/J (0.67 lb/MMBtu) heat input for gaseous fuels;
(ii)310 ng/J (0.72 lb/MMBtu) heat input for liquid fuels; and
(iii)990 ng/J (2.30 lb/MMBtu) heat input for solid fuels. *Potential electrical output capacity* means 33 percent of the maximum design heat input capacity of the steam generating unit, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr ( *e.g.* , a steam generating unit with a 100 MW (340 MMBtu/hr) fossil-fuel heat input capacity would have a 289,080 MWh 12 month potential electrical output capacity). For electric utility combined cycle gas turbines the potential electrical output capacity is determined on the basis of the fossil-fuel firing capacity of the steam generator exclusive of the heat input and electrical power contribution by the gas turbine. *Principal company* means the electric utility company or companies which own the affected facility. *Resource recovery unit* means a facility that combusts more than 75 percent non-fossil fuel on a quarterly (calendar) heat input basis. *Responsible official* means responsible official as defined in 40 CFR 70.2. *Solid-derived fuel* means any solid, liquid, or gaseous fuel derived from solid fuel for the purpose of creating useful heat and includes, but is not limited to, solvent refined coal, liquified coal, synthetic gas, gasified coal, gasified petroleum coke, gasified biomass, and gasified tire derived fuel. *Spare flue gas desulfurization system module* means a separate system of SO <sup>2</sup> emission control equipment capable of treating an amount of flue gas equal to the total amount of flue gas generated by an affected facility when operated at maximum capacity divided by the total number of nonspare flue gas desulfurization modules in the system. *Spinning reserve* means the sum of the unutilized net generating capability of all units of the electric utility company that are synchronized to the power distribution system and that are capable of immediately accepting additional load. The electric generating capability of equipment under multiple ownership is prorated based on ownership unless the proportional entitlement to electric output is otherwise established by contractual arrangement. *Steam generating unit* means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (including fossil-fuel-fired steam generators associated with combined cycle gas turbines; nuclear steam generators are not included). *Subbituminous coal* means coal that is classified as subbituminous A, B, or C according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17). *System emergency reserves* means an amount of electric generating capacity equivalent to the rated capacity of the single largest electric generating unit in the electric utility company (including steam generating units, internal combustion engines, gas turbines, nuclear units, hydroelectric units, and all other electric generating equipment) which is interconnected with the affected facility that has the malfunctioning flue gas desulfurization system. The electric generating capability of equipment under multiple ownership is prorated based on ownership unless the proportional entitlement to electric output is otherwise established by contractual arrangement. *System load* means the entire electric demand of an electric utility company's service area interconnected with the affected facility that has the malfunctioning flue gas desulfurization system plus firm contractual sales to other electric utility companies. Sales to other electric utility companies ( *e.g.* , emergency power) not on a firm contractual basis may also be included in the system load when no available system capacity exists in the electric utility company to which the power is supplied for sale. *Wet flue gas desulfurization technology* or *wet FGD* means a SO <sup>2</sup> control system that is located downstream of the steam generating unit and removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline slurry or solution and forming a liquid material. This definition applies to devices where the aqueous liquid material product of this contact is subsequently converted to other forms. Alkaline reagents used in wet FGD technology include, but are not limited to, lime, limestone, and sodium. § 60.42Da Standard for particulate matter (PM).
(a)On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility for which construction, reconstruction, or modification commenced before or on February 28, 2005, any gases that contain PM in excess of:
(1)13 ng/J (0.03 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel;
(2)1 percent of the potential combustion concentration (99 percent reduction) when combusting solid fuel; and
(3)30 percent of potential combustion concentration (70 percent reduction) when combusting liquid fuel.
(b)On and after the date the initial PM performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases which exhibit greater than 20 percent opacity (6-minute average), except for one 6-minute period per hour of not more than 27 percent opacity.
(c)Except as provided in paragraph
(d)of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after February 28, 2005 shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of either:
(1)18 ng/J (0.14 lb/MWh) gross energy output; or
(2)6.4 ng/J (0.015 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel.
(d)As an alternative to meeting the requirements of paragraph
(c)of this section, the owner or operator of an affected facility for which construction, reconstruction, or modification commenced after February 28, 2005, may elect to meet the requirements of this paragraph. On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from that affected facility for which construction, reconstruction, or modification commenced after February 28, 2005, any gases that contain PM in excess of:
(1)13 ng/J (0.03 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel, and
(2)0.1 percent of the combustion concentration determined according to the procedure in § 60.48Da(o)(5) (99.9 percent reduction) for an affected facility for which construction or reconstruction commenced after February 28, 2005 when combusting solid, liquid, or gaseous fuel, or
(3)0.2 percent of the combustion concentration determined according to the procedure in § 60.48Da(o)(5) (99.8 percent reduction) for an affected facility for which modification commenced after February 28, 2005 when combusting solid, liquid, or gaseous fuel. § 60.43Da Standard for sulfur dioxide (SO 2 ).
(a)On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility which combusts solid fuel or solid-derived fuel and for which construction, reconstruction, or modification commenced before or on February 28, 2005, except as provided under paragraphs (c), (d),
(f)or
(h)of this section, any gases that contain SO <sup>2</sup> in excess of:
(1)520 ng/J (1.20 lb/MMBtu) heat input and 10 percent of the potential combustion concentration (90 percent reduction); or
(2)30 percent of the potential combustion concentration (70 percent reduction), when emissions are less than 260 ng/J (0.60 lb/MMBtu) heat input.
(b)On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility which combusts liquid or gaseous fuels (except for liquid or gaseous fuels derived from solid fuels and as provided under paragraphs
(e)or
(h)of this section) and for which construction, reconstruction, or modification commenced before or on February 28, 2005, any gases that contain SO <sup>2</sup> in excess of:
(1)340 ng/J (0.80 lb/MMBtu) heat input and 10 percent of the potential combustion concentration (90 percent reduction); or
(2)100 percent of the potential combustion concentration (zero percent reduction) when emissions are less than 86 ng/J (0.20 lb/MMBtu) heat input.
(c)On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility which combusts solid solvent refined coal (SRC-I) any gases that contain SO <sup>2</sup> in excess of 520 ng/J (1.20 lb/MMBtu) heat input and 15 percent of the potential combustion concentration (85 percent reduction) except as provided under paragraph
(f)of this section; compliance with the emission limitation is determined on a 30-day rolling average basis and compliance with the percent reduction requirement is determined on a 24-hour basis.
(d)Sulfur dioxide emissions are limited to 520 ng/J (1.20 lb/MMBtu) heat input from any affected facility which:
(1)Combusts 100 percent anthracite;
(2)Is classified as a resource recovery unit; or
(3)Is located in a noncontinental area and combusts solid fuel or solid-derived fuel.
(e)Sulfur dioxide emissions are limited to 340 ng/J (0.80 lb/MMBtu) heat input from any affected facility which is located in a noncontinental area and combusts liquid or gaseous fuels (excluding solid-derived fuels).
(f)The emission reduction requirements under this section do not apply to any affected facility that is operated under an SO <sup>2</sup> commercial demonstration permit issued by the Administrator in accordance with the provisions of § 60.47Da.
(g)Compliance with the emission limitation and percent reduction requirements under this section are both determined on a 30-day rolling average basis except as provided under paragraph
(c)of this section.
(h)When different fuels are combusted simultaneously, the applicable standard is determined by proration using the following formula:
(1)If emissions of SO <sup>2</sup> to the atmosphere are greater than 260 ng/J (0.60 lb/MMBtu) heat input ER13JN07.008
(2)If emissions of SO <sup>2</sup> to the atmosphere are equal to or less than 260 ng/J (0.60 lb/MMBtu) heat input: ER13JN07.009 Where: E <sup>s</sup> = Prorated SO <sup>2</sup> emission limit (ng/J heat input); %P <sup>s</sup> = Percentage of potential SO <sup>2</sup> emission allowed; x = Percentage of total heat input derived from the combustion of liquid or gaseous fuels (excluding solid-derived fuels); and y = Percentage of total heat input derived from the combustion of solid fuel (including solid-derived fuels).
(i)Except as provided in paragraphs
(j)and
(k)of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification commenced after February 28, 2005 shall cause to be discharged into the atmosphere from that affected facility, any gases that contain SO <sup>2</sup> in excess of the applicable emission limitation specified in paragraphs (i)(1) through
(3)of this section.
(1)For an affected facility for which construction commenced after February 28, 2005, any gases that contain SO <sup>2</sup> in excess of either:
(i)180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; or
(ii)5 percent of the potential combustion concentration (95 percent reduction) on a 30-day rolling average basis.
(2)For an affected facility for which reconstruction commenced after February 28, 2005, any gases that contain SO <sup>2</sup> in excess of either:
(i)180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis;
(ii)65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average basis; or
(iii)5 percent of the potential combustion concentration (95 percent reduction) on a 30-day rolling average basis.
(3)For an affected facility for which modification commenced after February 28, 2005, any gases that contain SO <sup>2</sup> in excess of either:
(i)180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis;
(ii)65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average basis; or
(iii)10 percent of the potential combustion concentration (90 percent reduction) on a 30-day rolling average basis.
(j)On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification commenced after February 28, 2005, and that burns 75 percent or more (by heat input) coal refuse on a 12-month rolling average basis, shall caused to be discharged into the atmosphere from that affected facility any gases that contain SO <sup>2</sup> in excess of the applicable emission limitation specified in paragraphs (j)(1) through
(3)of this section.
(1)For an affected facility for which construction commenced after February 28, 2005, any gases that contain SO <sup>2</sup> in excess of either:
(i)180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; or
(ii)6 percent of the potential combustion concentration (94 percent reduction) on a 30-day rolling average basis.
(2)For an affected facility for which reconstruction commenced after February 28, 2005, any gases that contain SO <sup>2</sup> in excess of either:
(i)180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis;
(ii)65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average basis; or
(iii)6 percent of the potential combustion concentration (94 percent reduction) on a 30-day rolling average basis.
(3)For an affected facility for which modification commenced after February 28, 2005, any gases that contain SO <sup>2</sup> in excess of either:
(i)180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis;
(ii)65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average basis; or
(iii)10 percent of the potential combustion concentration (90 percent reduction) on a 30-day rolling average basis.
(k)On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility located in a noncontinental area that commenced construction, reconstruction, or modification commenced after February 28, 2005, shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO <sup>2</sup> in excess of the applicable emission limitation specified in paragraphs (k)(1) and
(2)of this section.
(1)For an affected facility that burns solid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO <sup>2</sup> in excess of 520 ng/J (1.2 lb/MMBtu) heat input on a 30-day rolling average basis.
(2)For an affected facility that burns other than solid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO <sup>2</sup> in excess of if the affected facility or 230 ng/J (0.54 lb/MMBtu) heat input on a 30-day rolling average basis. § 60.44Da Standard for nitrogen oxides (NO X ).
(a)On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility, except as provided under paragraphs (b), (d), (e), and
(f)of this section, any gases that contain NO <sup>X</sup> (expressed as NO <sup>2</sup> ) in excess of the following emission limits, based on a 30-day rolling average basis, except as provided under § 60.48Da(j)(1):
(1)NO <sup>X</sup> emission limits. Fuel type Emission limit for heat input ng/J lb/MMBtu Gaseous fuels: Coal-derived fuels 210 0.50 All other fuels 86 0.20 Liquid fuels: Coal-derived fuels 210 0.50 Shale oil 210 0.50 All other fuels 130 0.30 Solid fuels: Coal-derived fuels 210 0.50 Any fuel containing more than 25%, by weight, coal refuse
(1)Any fuel containing more than 25%, by weight, lignite if the lignite is mined in North Dakota, South Dakota, or Montana, and is combusted in a slag tap furnace 2 340 0.80 Any fuel containing more than 25%, by weight, lignite not subject to the 340 ng/J heat input emission limit 2 260 0.60 Subbituminous coal 210 0.50 Bituminous coal 260 0.60 Anthracite coal 260 0.60 All other fuels 260 0.60 1 Exempt from NO <sup>X</sup> standards and NO <sup>X</sup> monitoring requirements. 2 Any fuel containing less than 25%, by weight, lignite is not prorated but its percentage is added to the percentage of the predominant fuel.
(2)NO <sup>X</sup> reduction requirement. Fuel type Percent reduction of potential combustion concentration Gaseous fuels 25 Liquid fuels 30 Solid fuels 65
(b)The emission limitations under paragraph
(a)of this section do not apply to any affected facility which is combusting coal-derived liquid fuel and is operating under a commercial demonstration permit issued by the Administrator in accordance with the provisions of § 60.47Da.
(c)Except as provided under paragraphs (d), (e), and
(f)of this section, when two or more fuels are combusted simultaneously, the applicable standard is determined by proration using the following formula: ER13JN07.010 Where: E <sup>n</sup> = Applicable standard for NO <sup>X</sup> when multiple fuels are combusted simultaneously (ng/J heat input); w = Percentage of total heat input derived from the combustion of fuels subject to the 86 ng/J heat input standard; x = Percentage of total heat input derived from the combustion of fuels subject to the 130 ng/J heat input standard; y = Percentage of total heat input derived from the combustion of fuels subject to the 210 ng/J heat input standard; z = Percentage of total heat input derived from the combustion of fuels subject to the 260 ng/J heat input standard; and v = Percentage of total heat input delivered from the combustion of fuels subject to the 340 ng/J heat input standard. (d)(1) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction after July 9, 1997, but before or on February 28, 2005 shall cause to be discharged into the atmosphere any gases that contain NO <sup>X</sup> (expressed as NO <sup>2</sup> ) in excess of 200 ng/J (1.6 lb/MWh) gross energy output, based on a 30-day rolling average basis, except as provided under § 60.48Da(k).
(2)On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of affected facility for which reconstruction commenced after July 9, 1997, but before or on February 28, 2005 shall cause to be discharged into the atmosphere any gases that contain NO <sup>X</sup> (expressed as NO <sup>2</sup> ) in excess of 65 ng/J (0.15 lb/MMBtu) heat input, based on a 30-day rolling average basis.
(e)Except for an IGCC electric utility steam generating unit meeting the requirements of paragraph
(f)of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after February 28, 2005 shall cause to be discharged into the atmosphere from that affected facility any gases that contain NO <sup>X</sup> (expressed as NO <sup>2</sup> ) in excess of the applicable emission limitation specified in paragraphs (e)(1) through
(3)of this section.
(1)For an affected facility for which construction commenced after February 28, 2005, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO <sup>X</sup> (expressed as NO <sup>2</sup> ) in excess of 130 ng/J (1.0 lb/MWh) gross energy output on a 30-day rolling average basis, except as provided under § 60.48Da(k).
(2)For an affected facility for which reconstruction commenced after February 28, 2005, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO <sup>X</sup> (expressed as NO <sup>2</sup> ) in excess of either:
(i)130 ng/J (1.0 lb/MWh) gross energy output on a 30-day rolling average basis; or
(ii)47 ng/J (0.11 lb/MMBtu) heat input on a 30-day rolling average basis.
(3)For an affected facility for which modification commenced after February 28, 2005, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO <sup>X</sup> (expressed as NO <sup>2</sup> ) in excess of either:
(i)180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; or
(ii)65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average basis.
(f)On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, the owner or operator of an IGCC electric utility steam generating unit subject to the provisions of this subpart and for which construction, reconstruction, or modification commenced after February 28, 2005, shall meet the requirements specified in paragraphs (f)(1) through
(3)of this section.
(1)Except as provided for in paragraphs (f)(2) and
(3)of this section, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO <sup>X</sup> (expressed as NO <sup>2</sup> ) in excess of 130 ng/J (1.0 lb/MWh) gross energy output on a 30-day rolling average basis.
(2)When burning liquid fuel exclusively or in combination with solid-derived fuel such that the liquid fuel contributes 50 percent or more of the total heat input to the combined cycle combustion turbine, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO <sup>X</sup> (expressed as NO <sup>2</sup> ) in excess of 190 ng/J (1.5 lb/MWh) gross energy output on a 30-day rolling average basis.
(3)In cases when during a 30-day rolling average compliance period liquid fuel is burned in such a manner to meet the conditions in paragraph (f)(2) of this section for only a portion of the clock hours in the 30-day period, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO <sup>X</sup> (expressed as NO <sup>2</sup> ) in excess of the computed weighted-average emissions limit based on the proportion of gross energy output (in MWh) generated during the compliance period for each of emissions limits in paragraphs (f)(1) and
(2)of this section. § 60.45Da Standard for mercury (Hg).
(a)For each coal-fired electric utility steam generating unit other than an IGCC electric utility steam generating unit, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility for which construction, modification, or reconstruction commenced after January 30, 2004, any gases that contain mercury
(Hg)emissions in excess of each Hg emissions limit in paragraphs (a)(1) through
(5)of this section that applies to you. The Hg emissions limits in paragraphs (a)(1) through
(5)of this section are based on a 12-month rolling average basis using the procedures in § 60.50Da(h).
(1)For each coal-fired electric utility steam generating unit that burns only bituminous coal, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of 20 × 10 − 6 pound per megawatt hour (lb/MWh) or 0.020 lb/gigawatt-hour
(GWh)on an output basis. The International System of Units
(SI)equivalent is 0.0025 ng/J.
(2)For each coal-fired electric utility steam generating unit that burns only subbituminous coal:
(i)If your unit is located in a county-level geographical area receiving greater than 25 inches per year (in/yr) mean annual precipitation, based on the most recent publicly available U.S. Department of Agriculture 30-year data, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of 66 × 10 − 6 lb/MWh or 0.066 lb/GWh on an output basis. The SI equivalent is 0.0083 ng/J.
(ii)If your unit is located in a county-level geographical area receiving less than or equal to 25 in/yr mean annual precipitation, based on the most recent publicly available U.S. Department of Agriculture 30-year data, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of 97 × 10 − 6 lb/MWh or 0.097 lb/GWh on an output basis. The SI equivalent is 0.0122 ng/J.
(3)For each coal-fired electric utility steam generating unit that burns only lignite, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of 175 × 10 − 6 lb/MWh or 0.175 lb/GWh on an output basis. The SI equivalent is 0.0221 ng/J.
(4)For each coal-burning electric utility steam generating unit that burns only coal refuse, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of 16 × 10 − 6 lb/MWh or 0.016 lb/GWh on an output basis. The SI equivalent is 0.0020 ng/J.
(5)For each coal-fired electric utility steam generating unit that burns a blend of coals from different coal ranks ( *i.e.* , bituminous coal, subbituminous coal, lignite) or a blend of coal and coal refuse, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of the unit-specific Hg emissions limit established according to paragraph (a)(5)(i) or
(ii)of this section, as applicable to the affected unit.
(i)If you operate a coal-fired electric utility steam generating unit that burns a blend of coals from different coal ranks or a blend of coal and coal refuse, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of the computed weighted Hg emissions limit based on the Btu, MWh, or MJ) contributed by each coal rank burned during the compliance period and its applicable Hg emissions limit in paragraphs (a)(1) through
(4)of this section as determined using Equation 1 in this section. For each affected source, you must comply with the weighted Hg emissions limit calculated using Equation 1 in this section based on the total Hg emissions from the unit and the total Btu, MWh, or MJ contributed by all fuels burned during the compliance period. ER13JN07.011 Where: EL <sup>b</sup> = Total allowable Hg in lb/MWh that can be emitted to the atmosphere from any affected source being averaged according to this paragraph. EL <sup>i</sup> = Hg emissions limit for the subcategory i (coal rank) that applies to affected source, lb/MWh; HH <sup>i</sup> = For each affected source, the Btu, MWh, or MJ contributed by the corresponding subcategory i (coal rank) burned during the compliance period; and n = Number of subcategories (coal ranks) being averaged for an affected source.
(ii)If you operate a coal-fired electric utility steam generating unit that burns a blend of coals from different coal ranks or a blend of coal and coal refuse together with one or more non-regulated, supplementary fuels, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of the computed weighted Hg emission limit based on the Btu, MWh, or MJ contributed by each coal rank burned during the compliance period and its applicable Hg emissions limit in paragraphs (a)(1) through
(4)of this section as determined using Equation 1 in this section. For each affected source. You must comply with the weighted Hg emissions limit calculated using Equation 1 in this section based on the total Hg emissions from the unit contributed by both regulated and nonregulated fuels burned during the compliance period and the total Btu, MWh, or MJ contributed by both regulated and nonregulated fuels burned during the compliance period.
(b)For each IGCC electric utility steam generating unit, on and after the date on which the initial performance test required to be conducted under § 60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility for which construction, modification, or reconstruction commenced after January 30, 2004, any gases that contain Hg emissions in excess of 20 × 10 − 6 lb/MWh or 0.020 lb/GWh on an output basis. The SI equivalent is 0.0025 ng/J. This Hg emissions limit is based on a 12-month rolling average basis using the procedures in § 60.50Da(h). § 60.46Da [Reserved] § 60.47Da Commercial demonstration permit.
(a)An owner or operator of an affected facility proposing to demonstrate an emerging technology may apply to the Administrator for a commercial demonstration permit. The Administrator will issue a commercial demonstration permit in accordance with paragraph
(e)of this section. Commercial demonstration permits may be issued only by the Administrator, and this authority will not be delegated.
(b)An owner or operator of an affected facility that combusts solid solvent refined coal (SRC-I) and who is issued a commercial demonstration permit by the Administrator is not subject to the SO <sup>2</sup> emission reduction requirements under § 60.43Da(c) but must, as a minimum, reduce SO <sup>2</sup> emissions to 20 percent of the potential combustion concentration (80 percent reduction) for each 24-hour period of steam generator operation and to less than 520 ng/J (1.20 lb/MMBtu) heat input on a 30-day rolling average basis.
(c)An owner or operator of a fluidized bed combustion electric utility steam generator (atmospheric or pressurized) who is issued a commercial demonstration permit by the Administrator is not subject to the SO <sup>2</sup> emission reduction requirements under § 60.43Da(a) but must, as a minimum, reduce SO <sup>2</sup> emissions to 15 percent of the potential combustion concentration (85 percent reduction) on a 30-day rolling average basis and to less than 520 ng/J (1.20 lb/MMBtu) heat input on a 30-day rolling average basis.
(d)The owner or operator of an affected facility that combusts coal-derived liquid fuel and who is issued a commercial demonstration permit by the Administrator is not subject to the applicable NO <sup>X</sup> emission limitation and percent reduction under § 60.44Da(a) but must, as a minimum, reduce emissions to less than 300 ng/J (0.70 lb/MMBtu) heat input on a 30-day rolling average basis.
(e)Commercial demonstration permits may not exceed the following equivalent MW electrical generation capacity for any one technology category, and the total equivalent MW electrical generation capacity for all commercial demonstration plants may not exceed 15,000 MW. Technology Pollutant Equivalent electrical capacity (MW electrical output) Solid solvent refined coal (SCR I) SO 2 6,000-10,000 Fluidized bed combustion (atmospheric) SO 2 400-3,000 Fluidized bed combustion (pressurized) SO 2 400-1,200 Coal liquification NO X 750-10,000 Total allowable for all technologies 15,000 § 60.48Da Compliance provisions.
(a)Compliance with the PM emission limitation under § 60.42Da(a)(1) constitutes compliance with the percent reduction requirements for PM under § 60.42Da(a)(2) and (3).
(b)Compliance with the NO <sup>X</sup> emission limitation under § 60.44Da(a)(1) constitutes compliance with the percent reduction requirements under § 60.44Da(a)(2).
(c)The PM emission standards under § 60.42Da, the NO <sup>X</sup> emission standards under § 60.44Da, and the Hg emission standards under § 60.45Da apply at all times except during periods of startup, shutdown, or malfunction.
(d)During emergency conditions in the principal company, an affected facility with a malfunctioning flue gas desulfurization system may be operated if SO <sup>2</sup> emissions are minimized by:
(1)Operating all operable flue gas desulfurization system modules, and bringing back into operation any malfunctioned module as soon as repairs are completed,
(2)Bypassing flue gases around only those flue gas desulfurization system modules that have been taken out of operation because they were incapable of any SO <sup>2</sup> emission reduction or which would have suffered significant physical damage if they had remained in operation, and
(3)Designing, constructing, and operating a spare flue gas desulfurization system module for an affected facility larger than 365 MW (1,250 MMBtu/hr) heat input (approximately 125 MW electrical output capacity). The Administrator may at his discretion require the owner or operator within 60 days of notification to demonstrate spare module capability. To demonstrate this capability, the owner or operator must demonstrate compliance with the appropriate requirements under paragraph under § 60.43Da(a), (b), (d), (e), and
(h)for any period of operation lasting from 24 hours to 30 days when:
(i)Any one flue gas desulfurization module is not operated,
(ii)The affected facility is operating at the maximum heat input rate,
(iii)The fuel fired during the 24-hour to 30-day period is representative of the type and average sulfur content of fuel used over a typical 30-day period, and
(iv)The owner or operator has given the Administrator at least 30 days notice of the date and period of time over which the demonstration will be performed.
(e)After the initial performance test required under § 60.8, compliance with the SO <sup>2</sup> emission limitations and percentage reduction requirements under § 60.43Da and the NO <sup>X</sup> emission limitations under § 60.44Da is based on the average emission rate for 30 successive boiler operating days. A separate performance test is completed at the end of each boiler operating day after the initial performance test, and a new 30 day average emission rate for both SO <sup>2</sup> and NO <sup>X</sup> and a new percent reduction for SO <sup>2</sup> are calculated to show compliance with the standards.
(f)For the initial performance test required under § 60.8, compliance with the SO <sup>2</sup> emission limitations and percent reduction requirements under § 60.43Da and the NO <sup>X</sup> emission limitation under § 60.44Da is based on the average emission rates for SO <sup>2</sup> , NO <sup>X</sup> , and percent reduction for SO <sup>2</sup> for the first 30 successive boiler operating days. The initial performance test is the only test in which at least 30 days prior notice is required unless otherwise specified by the Administrator. The initial performance test is to be scheduled so that the first boiler operating day of the 30 successive boiler operating days is completed within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of the facility.
(g)The owner or operator of an affected facility subject to emission limitations in this subpart shall determine compliance as follows:
(1)Compliance with applicable 30-day rolling average SO <sup>2</sup> and NO <sup>X</sup> emission limitations is determined by calculating the arithmetic average of all hourly emission rates for SO <sup>2</sup> and NO <sup>X</sup> for the 30 successive boiler operating days, except for data obtained during startup, shutdown, malfunction (NO <sup>X</sup> only), or emergency conditions (SO <sup>2</sup> only).
(2)Compliance with applicable SO <sup>2</sup> percentage reduction requirements is determined based on the average inlet and outlet SO <sup>2</sup> emission rates for the 30 successive boiler operating days.
(3)Compliance with applicable daily average PM emission limitations is determined by calculating the arithmetic average of all hourly emission rates for PM each boiler operating day, except for data obtained during startup, shutdown, and malfunction. Averages are only calculated for boiler operating days that have valid data for at least 18 hours of unit operation during which the standard applies. Instead, the valid hourly emission rates are averaged with the next boiler operating day with 18 hours or more of valid PM CEMS data to determine compliance.
(h)If an owner or operator has not obtained the minimum quantity of emission data as required under § 60.49Da of this subpart, compliance of the affected facility with the emission requirements under §§ 60.43Da and 60.44Da of this subpart for the day on which the 30-day period ends may be determined by the Administrator by following the applicable procedures in section 7 of Method 19 of appendix A of this part.
(i)*Compliance provisions for sources subject to § 60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), or (f)* . The owner or operator of an affected facility subject to § 60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), or
(f)shall calculate NO <sup>X</sup> emissions as 1.194 × 10 − 7 lb/scf-ppm times the average hourly NO <sup>X</sup> output concentration in ppm (measured according to the provisions of § 60.49Da(c)), times the average hourly flow rate (measured in scfh, according to the provisions of § 60.49Da(l) or § 60.49Da(m)), divided by the average hourly gross energy output (measured according to the provisions of § 60.49Da(k)). Alternatively, for oil-fired and gas-fired units, NO <sup>X</sup> emissions may be calculated by multiplying the hourly NO <sup>X</sup> emission rate in lb/MMBtu (measured by the CEMS required under §§ 60.49Da(c) and (d)), by the hourly heat input rate (measured according to the provisions of § 60.49Da(n)), and dividing the result by the average gross energy output (measured according to the provisions of § 60.49Da(k)).
(j)*Compliance provisions for duct burners subject to § 60.44Da(a)(1)* . To determine compliance with the emissions limits for NO <sup>X</sup> required by § 60.44Da(a) for duct burners used in combined cycle systems, either of the procedures described in paragraph (j)(1) or
(2)of this section may be used:
(1)The owner or operator of an affected duct burner shall conduct the performance test required under § 60.8 using the appropriate methods in appendix A of this part. Compliance with the emissions limits under § 60.44Da(a)(1) is determined on the average of three (nominal 1-hour) runs for the initial and subsequent performance tests. During the performance test, one sampling site shall be located in the exhaust of the turbine prior to the duct burner. A second sampling site shall be located at the outlet from the heat recovery steam generating unit. Measurements shall be taken at both sampling sites during the performance test; or
(2)The owner or operator of an affected duct burner may elect to determine compliance by using the continuous emission monitoring system
(CEMS)specified under § 60.49Da for measuring NO <sup>X</sup> and oxygen (O <sup>2</sup> ) (or carbon dioxide (CO <sup>2</sup> )) and meet the requirements of § 60.49Da. Alternatively, data from a NO <sup>X</sup> emission rate ( *i.e.* , NO <sup>X</sup> -diluent) CEMS certified according to the provisions of § 75.20(c) of this chapter and appendix A to part 75 of this chapter, and meeting the quality assurance requirements of § 75.21 of this chapter and appendix B to part 75 of this chapter, may be used, with the following caveats. Data used to meet the requirements of § 60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter. The sampling site shall be located at the outlet from the steam generating unit. The NO <sup>X</sup> emission rate at the outlet from the steam generating unit shall constitute the NO <sup>X</sup> emission rate from the duct burner of the combined cycle system.
(k)*Compliance provisions for duct burners subject to § 60.44Da(d)(1) or (e)(1)* . To determine compliance with the emission limitation for NO <sup>X</sup> required by § 60.44Da(d)(1) or (e)(1) for duct burners used in combined cycle systems, either of the procedures described in paragraphs (k)(1) and
(2)of this section may be used:
(1)The owner or operator of an affected duct burner used in combined cycle systems shall determine compliance with the applicable NO <sup>X</sup> emission limitation in § 60.44Da(d)(1) or (e)(1) as follows:
(i)The emission rate
(E)of NO <sup>X</sup> shall be computed using Equation 2 in this section: ER13jn07.012 Where: E = Emission rate of NO <sup>X</sup> from the duct burner, ng/J (lb/MWh) gross output; C <sup>sg</sup> = Average hourly concentration of NO <sup>X</sup> exiting the steam generating unit, ng/dscm (lb/dscf); C <sup>te</sup> = Average hourly concentration of NO <sup>X</sup> in the turbine exhaust upstream from duct burner, ng/dscm (lb/dscf); Q <sup>sg</sup> = Average hourly volumetric flow rate of exhaust gas from steam generating unit, dscm/hr (dscf/hr); Q <sup>te</sup> = Average hourly volumetric flow rate of exhaust gas from combustion turbine, dscm/hr (dscf/hr); O <sup>sg</sup> = Average hourly gross energy output from steam generating unit, J (MWh); and h = Average hourly fraction of the total heat input to the steam generating unit derived from the combustion of fuel in the affected duct burner.
(ii)Method 7E of appendix A of this part shall be used to determine the NO <sup>X</sup> concentrations (C <sup>sg</sup> and C <sup>te</sup> ). Method 2, 2F or 2G of appendix A of this part, as appropriate, shall be used to determine the volumetric flow rates (Q <sup>sg</sup> and Q <sup>te</sup> ) of the exhaust gases. The volumetric flow rate measurements shall be taken at the same time as the concentration measurements.
(iii)The owner or operator shall develop, demonstrate, and provide information satisfactory to the Administrator to determine the average hourly gross energy output from the steam generating unit, and the average hourly percentage of the total heat input to the steam generating unit derived from the combustion of fuel in the affected duct burner.
(iv)Compliance with the applicable NO <sup>X</sup> emission limitation in § 60.44Da(d)(1) or (e)(1) is determined by the three-run average (nominal 1-hour runs) for the initial and subsequent performance tests.
(2)The owner or operator of an affected duct burner used in a combined cycle system may elect to determine compliance with the applicable NO <sup>X</sup> emission limitation in § 60.44Da(d)(1) or (e)(1) on a 30-day rolling average basis as indicated in paragraphs (k)(2)(i) through
(iv)of this section.
(i)The emission rate
(E)of NO <sup>X</sup> shall be computed using Equation 3 in this section: ER13jn07.013 Where: E = Emission rate of NO <sup>X</sup> from the duct burner, ng/J (lb/MWh) gross output; C <sup>sg</sup> = Average hourly concentration of NO <sup>X</sup> exiting the steam generating unit, ng/dscm (lb/dscf); Q <sup>sg</sup> = Average hourly volumetric flow rate of exhaust gas from steam generating unit, dscm/hr (dscf/hr); and O <sup>cc</sup> = Average hourly gross energy output from entire combined cycle unit, J (MWh).
(ii)The CEMS specified under § 60.49Da for measuring NO <sup>X</sup> and O <sup>2</sup> (or CO <sup>2</sup> ) shall be used to determine the average hourly NO <sup>X</sup> concentrations (C <sup>sg</sup> ). The continuous flow monitoring system specified in § 60.49Da(l) or § 60.49Da(m) shall be used to determine the volumetric flow rate (Q <sup>sg</sup> ) of the exhaust gas. If the option to use the flow monitoring system in § 60.49Da(m) is selected, the flow rate data used to meet the requirements of § 60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter. The sampling site shall be located at the outlet from the steam generating unit.
(iii)The continuous monitoring system specified under § 60.49Da(k) for measuring and determining gross energy output shall be used to determine the average hourly gross energy output from the entire combined cycle unit (O <sup>cc</sup> ), which is the combined output from the combustion turbine and the steam generating unit.
(iv)The owner or operator may, in lieu of installing, operating, and recording data from the continuous flow monitoring system specified in § 60.49Da(l), determine the mass rate (lb/hr) of NO <sup>X</sup> emissions by installing, operating, and maintaining continuous fuel flowmeters following the appropriate measurements procedures specified in appendix D of part 75 of this chapter. If this compliance option is selected, the emission rate
(E)of NO <sup>X</sup> shall be computed using Equation 4 in this section: ER13jn07.014 Where: E = Emission rate of NO <sup>X</sup> from the duct burner, ng/J (lb/MWh) gross output; ER <sup>sg</sup> = Average hourly emission rate of NO <sup>X</sup> exiting the steam generating unit heat input calculated using appropriate F factor as described in Method 19 of appendix A of this part, ng/J (lb/MMBtu); H <sup>cc</sup> = Average hourly heat input rate of entire combined cycle unit, J/hr (MMBtu/hr); and O <sup>cc</sup> = Average hourly gross energy output from entire combined cycle unit, J (MWh).
(3)When an affected duct burner steam generating unit utilizes a common steam turbine with one or more affected duct burner steam generating units, the owner or operator shall either:
(i)Determine compliance with the applicable NO <sup>X</sup> emissions limits by measuring the emissions combined with the emissions from the other unit(s) utilizing the common steam turbine; or
(ii)Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined gross energy output from the steam turbine for each of the affected duct burners. The Administrator may approve such demonstrated substitute methods for apportioning the combined gross energy output measured at the steam turbine whenever the demonstration ensures accurate estimation of emissions regulated under this part.
(l)*Compliance provisions for sources subject to § 60.45Da.* The owner or operator of an affected facility subject to § 60.45Da (new sources constructed or reconstructed after January 30, 2004) shall calculate the Hg emission rate (lb/MWh) for each calendar month of the year, using hourly Hg concentrations measured according to the provisions of § 60.49Da(p) in conjunction with hourly stack gas volumetric flow rates measured according to the provisions of § 60.49Da(l) or (m), and hourly gross electrical outputs, determined according to the provisions in § 60.49Da(k). Compliance with the applicable standard under § 60.45Da is determined on a 12-month rolling average basis.
(m)*Compliance provisions for sources subject to § 60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), or (j)(3)(i).* The owner or operator of an affected facility subject to § 60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), or (j)(3)(i) shall calculate SO <sup>2</sup> emissions as 1.660 × 10 -7 lb/scf-ppm times the average hourly SO <sup>2</sup> output concentration in ppm (measured according to the provisions of § 60.49Da(b)), times the average hourly flow rate (measured according to the provisions of § 60.49Da(l) or § 60.49Da(m)), divided by the average hourly gross energy output (measured according to the provisions of § 60.49Da(k)). Alternatively, for oil-fired and gas-fired units, SO <sup>2</sup> emissions may be calculated by multiplying the hourly SO <sup>2</sup> emission rate (in lb/MMBtu), measured by the CEMS required under § 60.49Da, by the hourly heat input rate (measured according to the provisions of § 60.49Da(n)), and dividing the result by the average gross energy output (measured according to the provisions of § 60.49Da(k)).
(n)*Compliance provisions for sources subject to § 60.42Da(c)(1).* The owner or operator of an affected facility subject to § 60.42Da(c)(1) shall calculate PM emissions by multiplying the average hourly PM output concentration, measured according to the provisions of § 60.49Da(t), by the average hourly flow rate, measured according to the provisions of § 60.49Da(l), and divided by the average hourly gross energy output, measured according to the provisions of § 60.49Da(k). Compliance with the emission limit is determined by calculating the arithmetic average of the hourly emission rates computed for each boiler operating day.
(o)*Compliance provisions for sources subject to § 60.42Da(c)(2) or (d).* Except as provided for in paragraph
(p)of this section, the owner or operator of an affected facility for which construction, reconstruction, or modification commenced after February 28, 2005, shall demonstrate compliance with each applicable emission limit according to the requirements in paragraphs (o)(1) through (o)(5) of this section and use a COMS to demonstrate compliance with § 60.42Da(b).
(1)You must conduct a performance test to demonstrate initial compliance with the applicable PM emissions limit in 60.42Da(c)(2) or
(d)by the applicable date specified in § 60.8(a). Thereafter, you must conduct each subsequent performance test within 12 calendar months of the date of the prior performance test. You must conduct each performance test according to the requirements in § 60.8 using the test methods and procedures in § 60.50Da.
(2)You must monitor the performance of each electrostatic precipitator or fabric filter (baghouse) operated to comply with the applicable PM emissions limit in § 60.42Da(c)(2) or
(d)using a continuous opacity monitoring system
(COMS)according to the requirements in paragraphs (o)(2)(i) through
(vi)unless you elect to comply with one of the alternatives provided in paragraphs (o)(3) and (o)(4) of this section, as applicable to your control device.
(i)Each COMS must meet Performance Specification 1 in 40 CFR part 60, appendix B.
(ii)You must comply with the quality assurance requirements in paragraphs (o)(4)(ii)(A) through
(E)of this section.
(A)You must automatically (intrinsic to the opacity monitor) check the zero and upscale
(span)calibration drifts at least once daily. For a particular COMS, the acceptable range of zero and upscale calibration materials is as defined in the applicable version of Performance Specification 1 in 40 CFR part 60, appendix B.
(B)You must adjust the zero and span whenever the 24-hour zero drift or 24-hour span drift exceeds 4 percent opacity. The COMS must allow for the amount of excess zero and span drift measured at the 24-hour interval checks to be recorded and quantified. The optical surfaces exposed to the effluent gases must be cleaned prior to performing the zero and span drift adjustments, except for systems using automatic zero adjustments. For systems using automatic zero adjustments, the optical surfaces must be cleaned when the cumulative automatic zero compensation exceeds 4 percent opacity.
(C)You must apply a method for producing a simulated zero opacity condition and an upscale
(span)opacity condition using a certified neutral density filter or other related technique to produce a known obscuration of the light beam. All procedures applied must provide a system check of the analyzer internal optical surfaces and all electronic circuitry including the lamp and photodetector assembly.
(D)Except during periods of system breakdowns, repairs, calibration checks, and zero and span adjustments, the COMS must be in continuous operation and must complete a minimum of one cycle of sampling and analyzing for each successive 10 second period and one cycle of data recording for each successive 6-minute period.
(E)You must reduce all data from the COMS to 6-minute averages. Six-minute opacity averages must be calculated from 36 or more data points equally spaced over each 6-minute period. Data recorded during periods of system breakdowns, repairs, calibration checks, and zero and span adjustments must not be included in the data averages. An arithmetic or integrated average of all data may be used.
(iii)During each performance test conducted according to paragraph (o)(1) of this section, you must establish an opacity baseline level. The value of the opacity baseline level is determined by averaging all of the 6-minute average opacity values (reported to the nearest 0.1 percent opacity) from the COMS measurements recorded during each of the test run intervals conducted for the performance test, and then adding 2.5 percent opacity to your calculated average opacity value for all of the test runs. If your calculated average opacity value for all of the test runs is less than 5.0 percent, then the opacity baseline level is set at 5.0 percent.
(iv)You must evaluate the preceding 24-hour average opacity level measured by the COMS each boiler operating day excluding periods of affected source startup, shutdown, or malfunction. If the measured 24-hour average opacity emission level is greater than the baseline opacity level determined in paragraph (o)(2)(iii) of this section, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of the high opacity incident and take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the measured 24-hour average opacity to a level below the baseline opacity level.
(v)You must record the opacity measurements, calculations performed, and any corrective actions taken. The record of corrective action taken must include the date and time during which the measured 24-hour average opacity was greater than baseline opacity level, and the date, time, and description of the corrective action.
(vi)If the measured 24-hour average opacity for your affected source remains at a level greater than the opacity baseline level after 7 days, then you must conduct a new PM performance test according to paragraph (o)(1) of this section and establish a new opacity baseline value according to paragraph (o)(2) of this section. This new performance test must be conducted within 60 days of the date that the measured 24-hour average opacity was first determined to exceed the baseline opacity level unless a wavier is granted by the appropriate delegated permitting authority.
(3)As an alternative to complying with the requirements of paragraph (o)(2) of this section, an owner or operator may elect to monitor the performance of an electrostatic precipitator
(ESP)operated to comply with the applicable PM emissions limit in § 60.42Da(c)(2) or
(d)using an ESP predictive model developed in accordance with the requirements in paragraphs (o)(3)(i) through
(v)of this section.
(i)You must calibrate the ESP predictive model with each PM control device used to comply with the applicable PM emissions limit in § 60.42Da(c)(2) or
(d)operating under normal conditions. In cases when a wet scrubber is used in combination with an ESP to comply with the PM emissions limit, the daily average liquid-to-gas flow rate for the wet scrubber must be maintained at 90 percent of average ratio measured during all test run intervals for the performance test conducted according to paragraph (o)(1) of this section.
(ii)You must develop a site-specific monitoring plan that includes a description of the ESP predictive model used, the model input parameters, and the procedures and criteria for establishing monitoring parameter baseline levels indicative of compliance with the PM emissions limit. You must submit the site-specific monitoring plan for approval by the appropriate delegated permitting authority. For reference purposes in preparing the monitoring plan, see the OAQPS “Compliance Assurance Monitoring
(CAM)Protocol for an Electrostatic Precipitator
(ESP)Controlling Particulate Matter
(PM)Emissions from a Coal-Fired Boiler.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality Planning and Standards; Sector Policies and Programs Division; Measurement Policy Group (D243-02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network
(TTN)under Emission Measurement Center Continuous Emission Monitoring .
(iii)You must run the ESP predictive model using the applicable input data each boiler operating day and evaluate the model output for the preceding boiler operating day excluding periods of affected source startup, shutdown, or malfunction. If the values for one or more of the model parameters exceed the applicable baseline levels determined according to your approved site-specific monitoring plan, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of a model parameter deviation and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to return the model output to within the applicable baseline levels.
(iv)You must record the ESP predictive model inputs and outputs and any corrective actions taken. The record of corrective action taken must include the date and time during which the model output values exceeded the applicable baseline levels, and the date, time, and description of the corrective action.
(v)If after 7 consecutive days a model parameter continues to exceed the applicable baseline level, then you must conduct a new PM performance test according to paragraph (o)(1) of this section. This new performance test must be conducted within 60 days of the date that the model parameter was first determined to exceed its baseline level unless a wavier is granted by the appropriate delegated permitting authority.
(4)As an alternative to complying with the requirements of paragraph (o)(2) of this section, an owner or operator may elect to monitor the performance of a fabric filter (baghouse) operated to comply with the applicable PM emissions limit in § 60.42Da(c)(2) or
(d)by using a bag leak detection system according to the requirements in paragraphs (o)(4)(i) through
(v)of this section.
(i)Each bag leak detection system must meet the specifications and requirements in paragraphs (o)(4)(i)(A) through
(H)of this section.
(A)The bag leak detection system must be certified by the manufacturer to be capable of detecting PM emissions at concentrations of 1 milligram per actual cubic meter (0.00044 grains per actual cubic foot) or less.
(B)The bag leak detection system sensor must provide output of relative PM loadings. The owner or operator must continuously record the output from the bag leak detection system using electronic or other means ( *e.g.* , using a strip chart recorder or a data logger.)
(C)The bag leak detection system must be equipped with an alarm system that will react when the system detects an increase in relative particulate loading over the alarm set point established according to paragraph (o)(4)(i)(D) of this section, and the alarm must be located such that it can be noticed by the appropriate plant personnel.
(D)In the initial adjustment of the bag leak detection system, you must establish, at a minimum, the baseline output by adjusting the sensitivity (range) and the averaging period of the device, the alarm set points, and the alarm delay time.
(E)Following initial adjustment, you must not adjust the averaging period, alarm set point, or alarm delay time without approval from the appropriate delegated permitting authority except as provided in paragraph (d)(1)(vi) of this section.
(F)Once per quarter, you may adjust the sensitivity of the bag leak detection system to account for seasonal effects, including temperature and humidity, according to the procedures identified in the site-specific monitoring plan required by paragraph (o)(4)(ii) of this section.
(G)You must install the bag leak detection sensor downstream of the fabric filter and upstream of any wet scrubber.
(H)Where multiple detectors are required, the system's instrumentation and alarm may be shared among detectors.
(ii)You must develop and submit to the appropriate delegated permitting authority for approval a site-specific monitoring plan for each bag leak detection system. You must operate and maintain the bag leak detection system according to the site-specific monitoring plan at all times. Each monitoring plan must describe the items in paragraphs (o)(4)(ii)(A) through
(F)of this section.
(A)Installation of the bag leak detection system;
(B)Initial and periodic adjustment of the bag leak detection system, including how the alarm set-point will be established;
(C)Operation of the bag leak detection system, including quality assurance procedures;
(D)How the bag leak detection system will be maintained, including a routine maintenance schedule and spare parts inventory list;
(E)How the bag leak detection system output will be recorded and stored; and
(F)Corrective action procedures as specified in paragraph (o)(4)(iii) of this section. In approving the site-specific monitoring plan, the appropriate delegated permitting authority may allow owners and operators more than 3 hours to alleviate a specific condition that causes an alarm if the owner or operator identifies in the monitoring plan this specific condition as one that could lead to an alarm, adequately explains why it is not feasible to alleviate this condition within 3 hours of the time the alarm occurs, and demonstrates that the requested time will ensure alleviation of this condition as expeditiously as practicable.
(iii)For each bag leak detection system, you must initiate procedures to determine the cause of every alarm within 1 hour of the alarm. Except as provided in paragraph (o)(4)(ii)(F) of this section, you must alleviate the cause of the alarm within 3 hours of the alarm by taking whatever corrective action(s) are necessary. Corrective actions may include, but are not limited to the following:
(A)Inspecting the fabric filter for air leaks, torn or broken bags or filter media, or any other condition that may cause an increase in particulate emissions;
(B)Sealing off defective bags or filter media;
(C)Replacing defective bags or filter media or otherwise repairing the control device;
(D)Sealing off a defective fabric filter compartment;
(E)Cleaning the bag leak detection system probe or otherwise repairing the bag leak detection system; or
(F)Shutting down the process producing the particulate emissions.
(iv)You must maintain records of the information specified in paragraphs (o)(4)(iv)(A) through
(C)of this section for each bag leak detection system.
(A)Records of the bag leak detection system output;
(B)Records of bag leak detection system adjustments, including the date and time of the adjustment, the initial bag leak detection system settings, and the final bag leak detection system settings; and
(C)The date and time of all bag leak detection system alarms, the time that procedures to determine the cause of the alarm were initiated, if procedures were initiated within 1 hour of the alarm, the cause of the alarm, an explanation of the actions taken, the date and time the cause of the alarm was alleviated, and if the alarm was alleviated within 3 hours of the alarm.
(v)If after any period of composed of 30 boiler operating days during which the alarm rate exceeds 5 percent of the process operating time (excluding control device or process startup, shutdown, and malfunction), then you must conduct a new PM performance test according to paragraph (o)(1) of this section. This new performance test must be conducted within 60 days of the date that the alarm rate was first determined to exceed 5 percent limit unless a wavier is granted by the appropriate delegated permitting authority.
(5)An owner or operator of a modified affected source electing to meet the emission limitations in § .42Da(d) shall determine the percent reduction in PM by using the emission rate for PM determined by the performance test conducted according to the requirements in paragraph (o)(1) of this section and the ash content on a mass basis of the fuel burned during each performance test run as determined by analysis of the fuel as fired.
(p)As an alternative to meeting the compliance provisions specified in paragraph
(o)of this section, an owner or operator may elect to install, certify, maintain, and operate a CEMS measuring PM emissions discharged from the affected facility to the atmosphere and record the output of the system as specified in paragraphs (p)(1) through (p)(8) of this section.
(1)The owner or operator shall submit a written notification to the Administrator of intent to demonstrate compliance with this subpart by using a CEMS measuring PM. This notification shall be sent at least 30 calendar days before the initial startup of the monitor for compliance determination purposes. The owner or operator may discontinue operation of the monitor and instead return to demonstration of compliance with this subpart according to the requirements in paragraph
(o)of this section by submitting written notification to the Administrator of such intent at least 30 calendar days before shutdown of the monitor for compliance determination purposes.
(2)Each CEMS shall be installed, certified, operated, and maintained according to the requirements in § 60.49Da(v).
(3)The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the affected facility, as specified under § 60.8 of subpart A of this part or within 180 days of the date of notification to the Administrator required under paragraph (p)(1) of this section, whichever is later.
(4)Compliance with the applicable emissions limit shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average emissions concentrations using the continuous monitoring system outlet data. The 24-hour block arithmetic average emission concentration shall be calculated using EPA Reference Method 19 of appendix A of this part, section 4.1.
(5)At a minimum, valid CEMS hourly averages shall be obtained for 75 percent of all operating hours on a 30-day rolling average basis. Beginning on January 1, 2012, valid CEMS hourly averages shall be obtained for 90 percent of all operating hours on a 30-day rolling average basis.
(i)At least two data points per hour shall be used to calculate each 1-hour arithmetic average.
(ii)[Reserved]
(6)The 1-hour arithmetic averages required shall be expressed in ng/J, MMBtu/hr, or lb/MWh and shall be used to calculate the boiler operating day daily arithmetic average emission concentrations. The 1-hour arithmetic averages shall be calculated using the data points required under § 60.13(e)(2) of subpart A of this part.
(7)All valid CEMS data shall be used in calculating average emission concentrations even if the minimum CEMS data requirements of paragraph (j)(5) of this section are not met.
(8)When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by the Administrator or EPA Reference Method 19 of appendix A of this part to provide, as necessary, valid emissions data for a minimum of 90 percent (only 75 percent is required prior to January 1, 2012) of all operating hours per 30-day rolling average. § 60.49Da Emission monitoring.
(a)Except as provided for in paragraphs
(t)and
(u)of this section, the owner or operator of an affected facility, shall install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring the opacity of emissions discharged to the atmosphere. If opacity interference due to water droplets exists in the stack (for example, from the use of an FGD system), the opacity is monitored upstream of the interference (at the inlet to the FGD system). If opacity interference is experienced at all locations (both at the inlet and outlet of the SO <sup>2</sup> control system), alternate parameters indicative of the PM control system's performance and/or good combustion are monitored (subject to the approval of the Administrator).
(b)The owner or operator of an affected facility shall install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring SO <sup>2</sup> emissions, except where natural gas is the only fuel combusted, as follows:
(1)Sulfur dioxide emissions are monitored at both the inlet and outlet of the SO <sup>2</sup> control device.
(2)For a facility that qualifies under the numerical limit provisions of § 60.43Da(d), (i), (j), or
(k)SO <sup>2</sup> emissions are only monitored as discharged to the atmosphere.
(3)An “as fired” fuel monitoring system (upstream of coal pulverizers) meeting the requirements of Method 19 of appendix A of this part may be used to determine potential SO <sup>2</sup> emissions in place of a continuous SO <sup>2</sup> emission monitor at the inlet to the SO <sup>2</sup> control device as required under paragraph (b)(1) of this section.
(4)If the owner or operator has installed and certified a SO <sup>2</sup> continuous emissions monitoring system
(CEMS)according to the requirements of § 75.20(c)(1) of this chapter and appendix A to part 75 of this chapter, and is continuing to meet the ongoing quality assurance requirements of § 75.21 of this chapter and appendix B to part 75 of this chapter, that CEMS may be used to meet the requirements of this section, provided that:
(i)A CO <sup>2</sup> or O <sup>2</sup> continuous monitoring system is installed, calibrated, maintained and operated at the same location, according to paragraph
(d)of this section; and
(ii)For sources subject to an SO <sup>2</sup> emission limit in lb/MMBtu under § 60.43Da:
(A)When relative accuracy testing is conducted, SO <sup>2</sup> concentration data and CO <sup>2</sup> (or O <sup>2</sup> ) data are collected simultaneously; and
(B)In addition to meeting the applicable SO <sup>2</sup> and CO <sup>2</sup> (or O <sup>2</sup> ) relative accuracy specifications in Figure 2 of appendix B to part 75 of this chapter, the relative accuracy
(RA)standard in section 13.2 of Performance Specification 2 in appendix B to this part is met when the RA is calculated on a lb/MMBtu basis; and
(iii)The reporting requirements of § 60.51Da are met. The SO <sup>2</sup> and CO <sup>2</sup> (or O <sup>2</sup> ) data reported to meet the requirements of § 60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the SO <sup>2</sup> data have been bias adjusted according to the procedures of part 75 of this chapter. (c)(1) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring NO <sup>X</sup> emissions discharged to the atmosphere; or
(2)If the owner or operator has installed a NO <sup>X</sup> emission rate CEMS to meet the requirements of part 75 of this chapter and is continuing to meet the ongoing requirements of part 75 of this chapter, that CEMS may be used to meet the requirements of this section, except that the owner or operator shall also meet the requirements of § 60.51Da. Data reported to meet the requirements of § 60.51Da shall not include data substituted using the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter.
(d)The owner or operator of an affected facility shall install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring the O <sup>2</sup> or carbon dioxide (CO <sup>2</sup> ) content of the flue gases at each location where SO <sup>2</sup> or NO <sup>X</sup> emissions are monitored. For affected facilities subject to a lb/MMBtu SO <sup>2</sup> emission limit under § 60.43Da, if the owner or operator has installed and certified a CO <sup>2</sup> or O <sup>2</sup> monitoring system according to § 75.20(c) of this chapter and Appendix A to part 75 of this chapter and the monitoring system continues to meet the applicable quality-assurance provisions of § 75.21 of this chapter and appendix B to part 75 of this chapter, that CEMS may be used together with the part 75 SO <sup>2</sup> concentration monitoring system described in paragraph
(b)of this section, to determine the SO <sup>2</sup> emission rate in lb/MMBtu. SO <sup>2</sup> data used to meet the requirements of § 60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter.
(e)The CEMS under paragraphs (b), (c), and
(d)of this section are operated and data recorded during all periods of operation of the affected facility including periods of startup, shutdown, malfunction or emergency conditions, except for CEMS breakdowns, repairs, calibration checks, and zero and span adjustments. (f)(1) For units that began construction, reconstruction, or modification on or before February 28, 2005, the owner or operator shall obtain emission data for at least 18 hours in at least 22 out of 30 successive boiler operating days. If this minimum data requirement cannot be met with CEMS, the owner or operator shall supplement emission data with other monitoring systems approved by the Administrator or the reference methods and procedures as described in paragraph
(h)of this section.
(2)For units that began construction, reconstruction, or modification after February 28, 2005, the owner or operator shall obtain emission data for at least 90 percent of all operating hours for each 30 successive boiler operating days. If this minimum data requirement cannot be met with a CEMS, the owner or operator shall supplement emission data with other monitoring systems approved by the Administrator or the reference methods and procedures as described in paragraph
(h)of this section.
(g)The 1-hour averages required under paragraph § 60.13(h) are expressed in ng/J (lb/MMBtu) heat input and used to calculate the average emission rates under § 60.48Da. The 1-hour averages are calculated using the data points required under § 60.13(h)(2).
(h)When it becomes necessary to supplement CEMS data to meet the minimum data requirements in paragraph
(f)of this section, the owner or operator shall use the reference methods and procedures as specified in this paragraph. Acceptable alternative methods and procedures are given in paragraph
(j)of this section.
(1)Method 6 of appendix A of this part shall be used to determine the SO <sup>2</sup> concentration at the same location as the SO <sup>2</sup> monitor. Samples shall be taken at 60-minute intervals. The sampling time and sample volume for each sample shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Each sample represents a 1-hour average.
(2)Method 7 of appendix A of this part shall be used to determine the NO <sup>X</sup> concentration at the same location as the NO <sup>X</sup> monitor. Samples shall be taken at 30-minute intervals. The arithmetic average of two consecutive samples represents a 1-hour average.
(3)The emission rate correction factor, integrated bag sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O <sup>2</sup> or CO <sup>2</sup> concentration at the same location as the O <sup>2</sup> or CO <sup>2</sup> monitor. Samples shall be taken for at least 30 minutes in each hour. Each sample represents a 1-hour average.
(4)The procedures in Method 19 of appendix A of this part shall be used to compute each 1-hour average concentration in ng/J (lb/MMBtu) heat input.
(i)The owner or operator shall use methods and procedures in this paragraph to conduct monitoring system performance evaluations under § 60.13(c) and calibration checks under § 60.13(d). Acceptable alternative methods and procedures are given in paragraph
(j)of this section.
(1)Methods 3B, 6, and 7 of appendix A of this part shall be used to determine O <sup>2</sup> , SO <sup>2</sup> , and NO <sup>X</sup> concentrations, respectively.
(2)SO <sup>2</sup> or NO <sup>X</sup> (NO), as applicable, shall be used for preparing the calibration gas mixtures (in N <sup>2</sup> , as applicable) under Performance Specification 2 of appendix B of this part.
(3)For affected facilities burning only fossil fuel, the span value for a CEMS for measuring opacity is between 60 and 80 percent. Span values for a CEMS measuring NO <sup>X</sup> shall be determined using one of the following procedures:
(i)Except as provided under paragraph (i)(3)(ii) of this section, NO <sup>X</sup> span values shall be determined as follows: Fossil fuel Span values for NO <sup>X</sup>
(ppm)Gas 500. Liquid 500. Solid 1,000. Combination 500 (x + y) + 1,000z. Where: x = Fraction of total heat input derived from gaseous fossil fuel, y = Fraction of total heat input derived from liquid fossil fuel, and z = Fraction of total heat input derived from solid fossil fuel.
(ii)As an alternative to meeting the requirements of paragraph (i)(3)(i) of this section, the owner or operator of an affected facility may elect to use the NO <sup>X</sup> span values determined according to section 2.1.2 in appendix A to part 75 of this chapter.
(4)All span values computed under paragraph (i)(3)(i) of this section for burning combinations of fossil fuels are rounded to the nearest 500 ppm. Span values computed under paragraph (i)(3)(ii) of this section shall be rounded off according to section 2.1.2 in appendix A to part 75 of this chapter.
(5)For affected facilities burning fossil fuel, alone or in combination with non-fossil fuel and determining span values under paragraph (i)(3)(i) of this section, the span value of the SO <sup>2</sup> CEMS at the inlet to the SO <sup>2</sup> control device is 125 percent of the maximum estimated hourly potential emissions of the fuel fired, and the outlet of the SO <sup>2</sup> control device is 50 percent of maximum estimated hourly potential emissions of the fuel fired. For affected facilities determining span values under paragraph (i)(3)(ii) of this section, SO <sup>2</sup> span values shall be determined according to section 2.1.1 in appendix A to part 75 of this chapter.
(j)The owner or operator may use the following as alternatives to the reference methods and procedures specified in this section:
(1)For Method 6 of appendix A of this part, Method 6A or 6B (whenever Methods 6 and 3 or 3B of appendix A of this part data are used) or 6C of appendix A of this part may be used. Each Method 6B of appendix A of this part sample obtained over 24 hours represents 24 1-hour averages. If Method 6A or 6B of appendix A of this part is used under paragraph
(i)of this section, the conditions under § 60.48Da(d)(1) apply; these conditions do not apply under paragraph
(h)of this section.
(2)For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or 7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of appendix A of this part is used, the sampling time for each run shall be 1 hour.
(3)For Method 3 of appendix A of this part, Method 3A or 3B of appendix A of this part may be used if the sampling time is 1 hour.
(4)For Method 3B of appendix A of this part, Method 3A of appendix A of this part may be used.
(k)The procedures specified in paragraphs (k)(1) through
(3)of this section shall be used to determine gross output for sources demonstrating compliance with the output-based standard under § 60.44Da(d)(1).
(1)The owner or operator of an affected facility with electricity generation shall install, calibrate, maintain, and operate a wattmeter; measure gross electrical output in MWh on a continuous basis; and record the output of the monitor.
(2)The owner or operator of an affected facility with process steam generation shall install, calibrate, maintain, and operate meters for steam flow, temperature, and pressure; measure gross process steam output in joules per hour (or Btu per hour) on a continuous basis; and record the output of the monitor.
(3)For affected facilities generating process steam in combination with electrical generation, the gross energy output is determined from the gross electrical output measured in accordance with paragraph (k)(1) of this section plus 75 percent of the gross thermal output (measured relative to ISO conditions) of the process steam measured in accordance with paragraph (k)(2) of this section.
(l)The owner or operator of an affected facility demonstrating compliance with an output-based standard under § 60.42Da, § 60.43Da, § 60.44Da, or § 60.45Da shall install, certify, operate, and maintain a continuous flow monitoring system meeting the requirements of Performance Specification 6 of appendix B of this part and the CD assessment, RATA and reporting provisions of procedure 1 of appendix F of this part, and record the output of the system, for measuring the volumetric flow rate of exhaust gases discharged to the atmosphere; or
(m)Alternatively, data from a continuous flow monitoring system certified according to the requirements of § 75.20(c) of this chapter and appendix A to part 75 of this chapter, and continuing to meet the applicable quality control and quality assurance requirements of § 75.21 of this chapter and appendix B to part 75 of this chapter, may be used. Flow rate data reported to meet the requirements of § 60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter.
(n)Gas-fired and oil-fired units. The owner or operator of an affected unit that qualifies as a gas-fired or oil-fired unit, as defined in 40 CFR 72.2, may use, as an alternative to the requirements specified in either paragraph
(l)or
(m)of this section, a fuel flow monitoring system certified and operated according to the requirements of appendix D of part 75 of this chapter.
(o)The owner or operator of a duct burner, as described in § 60.41Da, which is subject to the NO <sup>X</sup> standards of § 60.44Da(a)(1), (d)(1), or (e)(1) is not required to install or operate a CEMS to measure NO <sup>X</sup> emissions; a wattmeter to measure gross electrical output; meters to measure steam flow, temperature, and pressure; and a continuous flow monitoring system to measure the flow of exhaust gases discharged to the atmosphere.
(p)The owner or operator of an affected facility demonstrating compliance with an Hg limit in § 60.45Da shall install and operate a CEMS to measure and record the concentration of Hg in the exhaust gases from each stack according to the requirements in paragraphs (p)(1) through (p)(3) of this section. Alternatively, for an affected facility that is also subject to the requirements of subpart I of part 75 of this chapter, the owner or operator may install, certify, maintain, operate and quality-assure the data from a Hg CEMS according to § 75.10 of this chapter and appendices A and B to part 75 of this chapter, in lieu of following the procedures in paragraphs (p)(1) through (p)(3) of this section.
(1)The owner or operator must install, operate, and maintain each CEMS according to Performance Specification 12A in appendix B to this part.
(2)The owner or operator must conduct a performance evaluation of each CEMS according to the requirements of § 60.13 and Performance Specification 12A in appendix B to this part.
(3)The owner or operator must operate each CEMS according to the requirements in paragraphs (p)(3)(i) through
(iv)of this section.
(i)As specified in § 60.13(e)(2), each CEMS must complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period.
(ii)The owner or operator must reduce CEMS data as specified in § 60.13(h).
(iii)The owner or operator shall use all valid data points collected during the hour to calculate the hourly average Hg concentration.
(iv)The owner or operator must record the results of each required certification and quality assurance test of the CEMS.
(4)Mercury CEMS data collection must conform to paragraphs (p)(4)(i) through
(iv)of this section.
(i)For each calendar month in which the affected unit operates, valid hourly Hg concentration data, stack gas volumetric flow rate data, moisture data (if required), and electrical output data (i.e., valid data for all of these parameters) shall be obtained for at least 75 percent of the unit operating hours in the month.
(ii)Data reported to meet the requirements of this subpart shall not include hours of unit startup, shutdown, or malfunction. In addition, for an affected facility that is also subject to subpart I of part 75 of this chapter, data reported to meet the requirements of this subpart shall not include data substituted using the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter.
(iii)If valid data are obtained for less than 75 percent of the unit operating hours in a month, you must discard the data collected in that month and replace the data with the mean of the individual monthly emission rate values determined in the last 12 months. In the 12-month rolling average calculation, this substitute Hg emission rate shall be weighted according to the number of unit operating hours in the month for which the data capture requirement of § 60.49Da(p)(4)(i) was not met.
(iv)Notwithstanding the requirements of paragraph (p)(4)(iii) of this section, if valid data are obtained for less than 75 percent of the unit operating hours in another month in that same 12-month rolling average cycle, discard the data collected in that month and replace the data with the highest individual monthly emission rate determined in the last 12 months. In the 12-month rolling average calculation, this substitute Hg emission rate shall be weighted according to the number of unit operating hours in the month for which the data capture requirement of § 60.49Da(p)(4)(i) was not met.
(q)As an alternative to the CEMS required in paragraph
(p)of this section, the owner or operator may use a sorbent trap monitoring system (as defined in § 72.2 of this chapter) to monitor Hg concentration, according to the procedures described in § 75.15 of this chapter and appendix K to part 75 of this chapter.
(r)For Hg CEMS that measure Hg concentration on a dry basis or for sorbent trap monitoring systems, the emissions data must be corrected for the stack gas moisture content. A certified continuous moisture monitoring system that meets the requirements of § 75.11(b) of this chapter is acceptable for this purpose. Alternatively, the appropriate default moisture value, as specified in § 75.11(b) or § 75.12(b) of this chapter, may be used.
(s)The owner or operator shall prepare and submit to the Administrator for approval a unit-specific monitoring plan for each monitoring system, at least 45 days before commencing certification testing of the monitoring systems. The owner or operator shall comply with the requirements in your plan. The plan must address the requirements in paragraphs (s)(1) through
(6)of this section.
(1)Installation of the CEMS sampling probe or other interface at a measurement location relative to each affected process unit such that the measurement is representative of the exhaust emissions ( *e.g.* , on or downstream of the last control device);
(2)Performance and equipment specifications for the sample interface, the pollutant concentration or parametric signal analyzer, and the data collection and reduction systems;
(3)Performance evaluation procedures and acceptance criteria ( *e.g.,* calibrations, relative accuracy test audits (RATA), etc.);
(4)Ongoing operation and maintenance procedures in accordance with the general requirements of § 60.13(d) or part 75 of this chapter (as applicable);
(5)Ongoing data quality assurance procedures in accordance with the general requirements of § 60.13 or part 75 of this chapter (as applicable); and
(6)Ongoing recordkeeping and reporting procedures in accordance with the requirements of this subpart.
(t)The owner or operator of an affected facility demonstrating compliance with the output-based emissions limitation under § 60.42Da(c)(1) shall install, certify, operate, and maintain a CEMS for measuring PM emissions according to the requirements of paragraph
(v)of this section. An owner or operator of an affected source demonstrating compliance with the input-based emission limitation under § 60.42Da(c)(2) may install, certify, operate, and maintain a CEMS for measuring PM emissions according to the requirements of paragraph
(v)of this section.
(u)An owner or operator of an affected source that meets the conditions in either paragraph (u)(1),
(2)or
(3)of this section is exempted from the continuous opacity monitoring system requirements in paragraph
(a)of this section and the monitoring requirements in § 60.48Da(o).
(1)A CEMS for measuring PM emissions is used to demonstrate continuous compliance on a boiler operating day average with the emissions limitations under § 60.42Da(a)(1) or § 60.42Da(c)(2) and is installed, certified, operated, and maintained on the affected source according to the requirements of paragraph
(v)of this section; or
(2)The affected source burns only gaseous fuels and does not use a post-combustion technology to reduce emissions of SO <sup>2</sup> or PM; or
(3)The affected source does not use post-combustion technology (except a wet scrubber) for reducing PM, SO <sup>2</sup> , or carbon monoxide
(CO)emissions, burns only natural gas, gaseous fuels, or fuel oils that contain less than or equal to 0.30 weight percent sulfur, and is operated such that emissions of CO to the atmosphere from the affected source are maintained at levels less than or equal to 1.4 lb/MWh on a boiler operating day average basis. Owners and operators of affected sources electing to comply with this paragraph must demonstrate compliance according to the procedures specified in paragraphs (u)(3)(i) through
(iv)of this section.
(i)You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs (u)(3)(i)(A) through
(D)of this section.
(A)The CO CEMS must be installed, certified, maintained, and operated according to the provisions in § 60.58b(i)(3) of subpart Eb of this part.
(B)Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis).
(C)At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-day rolling average basis. At least two data points per hour must be used to calculate each 1-hour average.
(D)Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be performed in accordance with procedure 1 in appendix F of this part.
(ii)You must calculate the 1-hour average CO emissions levels for each boiler operating day by multiplying the average hourly CO output concentration measured by the CO CEMS times the corresponding average hourly flue gas flow rate and divided by the corresponding average hourly useful energy output from the affected source. The 24-hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission levels computed for each boiler operating day.
(iii)You must evaluate the preceding 24-hour average CO emission level each boiler operating day excluding periods of affected source startup, shutdown, or malfunction. If the 24-hour average CO emission level is greater than 1.4 lb/MWh, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of the high emission incident and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 1.4 lb/MWh or less.
(iv)You must record the CO measurements and calculations performed according to paragraph (u)(3) of this section and any corrective actions taken. The record of corrective action taken must include the date and time during which the 24-hour average CO emission level was greater than 1.4 lb/MWh, and the date, time, and description of the corrective action.
(v)The owner or operator of an affected facility using a CEMS measuring PM emissions to meet requirements of this subpart shall install, certify, operate, and maintain the CEMS as specified in paragraphs (v)(1) through (v)(3).
(1)The owner or operator shall conduct a performance evaluation of the CEMS according to the applicable requirements of § 60.13, Performance Specification 11 in appendix B of this part, and procedure 2 in appendix F of this part.
(2)During each relative accuracy test run of the CEMS required by Performance Specification 11 in appendix B of this part, PM and O <sup>2</sup> (or CO <sup>2</sup> ) data shall be collected concurrently (or within a 30-to 60-minute period) by both the CEMS and conducting performance tests using the following test methods.
(i)For PM, EPA Reference Method 5, 5B, or 17 of appendix A of this part shall be used.
(ii)For O <sup>2</sup> (or CO <sup>2</sup> ), EPA Reference Method 3, 3A, or 3B of appendix A of this part, as applicable shall be used.
(3)Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 2 in appendix F of this part. Relative Response Audit's must be performed annually and Response Correlation Audits must be performed every 3 years. (w)(1) Except as provided for under paragraphs (w)(2), (w)(3), and (w)(4) of this section, the SO <sup>2</sup> , NO <sup>X</sup> , CO <sup>2</sup> , and O <sup>2</sup> CEMS required under paragraphs
(b)through
(d)of this section shall be installed, certified, and operated in accordance with the applicable procedures in Performance Specification 2 or 3 in appendix B to this part or according to the procedures in appendices A and B to part 75 of this chapter. Daily calibration drift assessments and quarterly accuracy determinations shall be done in accordance with Procedure 1 in appendix F to this part, and a data assessment report (DAR), prepared according to section 7 of Procedure 1 in appendix F to this part, shall be submitted with each compliance report required under § 60.51Da., the owner or operator may elect to implement the following alternative data accuracy assessment procedures:
(2)As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to may elect to implement the following alternative data accuracy assessment procedures. For all required CO <sup>2</sup> and O <sup>2</sup> CEMS and for SO <sup>2</sup> and NO <sup>X</sup> CEMS with span values greater than 100 ppm, the daily calibration error test and calibration adjustment procedures described in sections 2.1.1 and 2.1.3 of appendix B to part 75 of this chapter may be followed instead of the CD assessment procedures in Procedure 1, section 4.1 of appendix F of this part. If this option is selected, the data validation and out-of-control provisions in sections 2.1.4 and 2.1.5 of appendix B to part 75 of this chapter shall be followed instead of the excessive CD and out-of-control criteria in Procedure 1, section 4.3 of appendix F to this part. For the purposes of data validation under this subpart, the excessive CD and out-of-control criteria in Procedure 1, section 4.3 of appendix F to this part shall apply to SO <sup>2</sup> and NO <sup>X</sup> span values less than 100 ppm;
(3)As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to may elect to implement the following alternative data accuracy assessment procedures. For all required CO <sup>2</sup> and O <sup>2</sup> CEMS and for SO <sup>2</sup> and NO <sup>X</sup> CEMS with span values greater than 30 ppm, quarterly linearity checks may be performed in accordance with section 2.2.1 of appendix B to part 75 of this chapter, instead of performing the cylinder gas audits
(CGAs)described in Procedure 1, section 5.1.2 of appendix F to this part. If this option is selected: The frequency of the linearity checks shall be as specified in section 2.2.1 of appendix B to part 75 of this chapter; the applicable linearity specifications in section 3.2 of appendix A to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.2.3 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this part; and the grace period provisions in section 2.2.4 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the cylinder gas audits described in Procedure 1, section 5.1.2 of appendix F to this part shall be performed for SO <sup>2</sup> and NO <sup>X</sup> span values less than or equal to 30 ppm;
(4)As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to may elect to implement the following alternative data accuracy assessment procedures. For SO <sup>2</sup> , CO <sup>2</sup> , and O <sup>2</sup> CEMS and for NO <sup>X</sup> CEMS, RATAs may be performed in accordance with section 2.3 of appendix B to part 75 of this chapter instead of following the procedures described in Procedure 1, section 5.1.1 of appendix F to this part. If this option is selected: The frequency of each RATA shall be as specified in section 2.3.1 of appendix B to part 75 of this chapter; the applicable relative accuracy specifications shown in Figure 2 in appendix B to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.3.2 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this part; and the grace period provisions in section 2.3.3 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the relative accuracy specification in section 13.2 of Performance Specification 2 in appendix B to this part shall be met on a lb/MMBtu basis for SO <sup>2</sup> (regardless of the SO <sup>2</sup> emission level during the RATA), and for NO <sup>X</sup> when the average NO <sup>X</sup> emission rate measured by the reference method during the RATA is less than 0.100 lb/MMBtu;
(5)If the owner or operator elects to implement the alternative data assessment procedures described in paragraphs (w)(2) through (w)(4) of this section, each data assessment report shall include a summary of the results of all of the RATAs, linearity checks, CGAs, and calibration error or drift assessments required by paragraphs (w)(2) through (w)(4) of this section. § 60.50Da Compliance determination procedures and methods.
(a)In conducting the performance tests required in § 60.8, the owner or operator shall use as reference methods and procedures the methods in appendix A of this part or the methods and procedures as specified in this section, except as provided in § 60.8(b). Section 60.8(f) does not apply to this section for SO <sup>2</sup> and NO <sup>X</sup> . Acceptable alternative methods are given in paragraph
(e)of this section.
(b)The owner or operator shall determine compliance with the PM standards in § 60.42Da as follows:
(1)The dry basis F factor (O <sup>2</sup> ) procedures in Method 19 of appendix A of this part shall be used to compute the emission rate of PM.
(2)For the particular matter concentration, Method 5 of appendix A of this part shall be used at affected facilities without wet FGD systems and Method 5B of appendix A of this part shall be used after wet FGD systems.
(i)The sampling time and sample volume for each run shall be at least 120 minutes and 1.70 dscm (60 dscf). The probe and filter holder heating system in the sampling train may be set to provide an average gas temperature of no greater than 160±14 °C (320±25 °F).
(ii)For each particulate run, the emission rate correction factor, integrated or grab sampling and analysis procedures of Method 3B of appendix A of this part shall be used to determine the O <sup>2</sup> concentration. The O <sup>2</sup> sample shall be obtained simultaneously with, and at the same traverse points as, the particulate run. If the particulate run has more than 12 traverse points, the O <sup>2</sup> traverse points may be reduced to 12 provided that Method 1 of appendix A of this part is used to locate the 12 O <sup>2</sup> traverse points. If the grab sampling procedure is used, the O <sup>2</sup> concentration for the run shall be the arithmetic mean of the sample O <sup>2</sup> concentrations at all traverse points.
(3)Method 9 of appendix A of this part and the procedures in § 60.11 shall be used to determine opacity.
(c)The owner or operator shall determine compliance with the SO <sup>2</sup> standards in § 60.43Da as follows:
(1)The percent of potential SO <sup>2</sup> emissions (%Ps) to the atmosphere shall be computed using the following equation: ER13JN07.015 Where: %Ps = Percent of potential SO <sup>2</sup> emissions, percent; %Rf = Percent reduction from fuel pretreatment, percent; and %Rg = Percent reduction by SO <sup>2</sup> control system, percent.
(2)The procedures in Method 19 of appendix A of this part may be used to determine percent reduction (%R <sup>f</sup> ) of sulfur by such processes as fuel pretreatment (physical coal cleaning, hydrodesulfurization of fuel oil, etc.), coal pulverizers, and bottom and fly ash interactions. This determination is optional.
(3)The procedures in Method 19 of appendix A of this part shall be used to determine the percent SO <sup>2</sup> reduction (%R <sup>g</sup> ) of any SO <sup>2</sup> control system. Alternatively, a combination of an “as fired” fuel monitor and emission rates measured after the control system, following the procedures in Method 19 of appendix A of this part, may be used if the percent reduction is calculated using the average emission rate from the SO <sup>2</sup> control device and the average SO <sup>2</sup> input rate from the “as fired” fuel analysis for 30 successive boiler operating days.
(4)The appropriate procedures in Method 19 of appendix A of this part shall be used to determine the emission rate.
(5)The CEMS in § 60.49Da(b) and
(d)shall be used to determine the concentrations of SO <sup>2</sup> and CO <sup>2</sup> or O <sup>2</sup> .
(d)The owner or operator shall determine compliance with the NO <sup>X</sup> standard in § 60.44Da as follows:
(1)The appropriate procedures in Method 19 of appendix A of this part shall be used to determine the emission rate of NO <sup>X</sup> .
(2)The continuous monitoring system in § 60.49Da(c) and
(d)shall be used to determine the concentrations of NO <sup>X</sup> and CO <sup>2</sup> or O <sup>2</sup> .
(e)The owner or operator may use the following as alternatives to the reference methods and procedures specified in this section:
(1)For Method 5 or 5B of appendix A of this part, Method 17 of appendix A of this part may be used at facilities with or without wet FGD systems if the stack temperature at the sampling location does not exceed an average temperature of 160 °C (320 °F). The procedures of §§ 2.1 and 2.3 of Method 5B of appendix A of this part may be used in Method 17 of appendix A of this part only if it is used after wet FGD systems. Method 17 of appendix A of this part shall not be used after wet FGD systems if the effluent is saturated or laden with water droplets.
(2)The F <sup>c</sup> factor (CO <sup>2</sup> ) procedures in Method 19 of appendix A of this part may be used to compute the emission rate of PM under the stipulations of § 60.46(d)(1). The CO <sup>2</sup> shall be determined in the same manner as the O <sup>2</sup> concentration.
(f)Electric utility combined cycle gas turbines are performance tested for PM, SO <sup>2</sup> , and NO <sup>X</sup> using the procedures of Method 19 of appendix A of this part. The SO <sup>2</sup> and NO <sup>X</sup> emission rates from the gas turbine used in Method 19 of appendix A of this part calculations are determined when the gas turbine is performance tested under subpart GG of this part. The potential uncontrolled PM emission rate from a gas turbine is defined as 17 ng/J (0.04 lb/MMBtu) heat input.
(g)For the purposes of determining compliance with the emission limits in § 60.45Da, the owner or operator of an electric utility steam generating unit which is also a cogeneration unit shall use the procedures in paragraphs (g)(1) and
(2)of this section to calculate emission rates based on electrical output to the grid plus 75 percent of the equivalent electrical energy (measured relative to ISO conditions) in the unit's process stream.
(1)All conversions from Btu/hr unit input to MW unit output must use equivalents found in 40 CFR 60.40(a)(1) for electric utilities ( *i.e.* , 250 MMBtu/hr input to an electric utility steam generating unit is equivalent to 73 MW input to the electric utility steam generating unit); 73 MW input to the electric utility steam generating unit is equivalent to 25 MW output from the boiler electric utility steam generating unit; therefore, 250 MMBtu input to the electric utility steam generating unit is equivalent to 25 MW output from the electric utility steam generating unit).
(2)Use the Equation 5 in this section to determine the cogeneration Hg emission rate over a specific compliance period. ER13JN07.016 Where: ER <sup>cogen</sup> = Cogeneration Hg emission rate over a compliance period in lb/MWh; E = Mass of Hg emitted from the stack over the same compliance period (lb); V <sup>grid</sup> = Amount of energy sent to the grid over the same compliance period (MWh); and V <sup>process</sup> = Amount of energy converted to steam for process use over the same compliance period (MWh).
(h)The owner or operator shall determine compliance with the Hg limit in § 60.45Da according to the procedures in paragraphs (h)(1) through
(3)of this section.
(1)The initial performance test shall be commenced by the applicable date specified in § 60.8(a). The required CEMS must be certified prior to commencing the test. The performance test consists of collecting hourly Hg emission data (lb/MWh) with the CEMS for 12 successive months of unit operation (excluding hours of unit startup, shutdown and malfunction). The average Hg emission rate is calculated for each month, and then the weighted, 12-month average Hg emission rate is calculated according to paragraph (h)(2) or (h)(3) of this section, as applicable. If, for any month in the initial performance test, the minimum data capture requirement in § 60.49Da(p)(4)(i) is not met, the owner or operator shall report a substitute Hg emission rate for that month, as follows. For the first such month, the substitute monthly Hg emission rate shall be the arithmetic average of all valid hourly Hg emission rates recorded to date. For any subsequent month(s) with insufficient data capture, the substitute monthly Hg emission rate shall be the highest valid hourly Hg emission rate recorded to date. When the 12-month average Hg emission rate for the initial performance test is calculated, for each month in which there was insufficient data capture, the substitute monthly Hg emission rate shall be weighted according to the number of unit operating hours in that month. Following the initial performance test, the owner or operator shall demonstrate compliance by calculating the weighted average of all monthly Hg emission rates (in lb/MWh) for each 12 successive calendar months, excluding data obtained during startup, shutdown, or malfunction.
(2)If a CEMS is used to demonstrate compliance, follow the procedures in paragraphs (h)(2)(i) through
(iii)of this section to determine the 12-month rolling average.
(i)Calculate the total mass of Hg emissions over a month (M), in lb, using either Equation 6 in paragraph (h)(2)(i)(A) of this section or Equation 7 in paragraph (h)(2)(i)(B) of this section, in conjunction with Equation 8 in paragraph (h)(2)(i)(C) of this section.
(A)If the Hg CEMS measures Hg concentration on a wet basis, use Equation 6 below to calculate the Hg mass emissions for each valid hour: ER13JN07.017 Where: E <sup>h</sup> = Hg mass emissions for the hour, (lb); K = Units conversion constant, 6.24 × 10 − 11 lb-scm/μgm-scf; C <sup>h</sup> = Hourly H <sup>g</sup> concentration, wet basis, (μgm/scm); Q <sup>h</sup> = Hourly stack gas volumetric flow rate, (scfh); and t <sup>h</sup> = Unit operating time, i.e., the fraction of the hour for which the unit operated. For example, th = 0.50 for a half-hour of unit operation and 1.00 for a full hour of operation.
(B)If the Hg CEMS measures Hg concentration on a dry basis, use Equation 7 below to calculate the Hg mass emissions for each valid hour: ER13JN07.018 Where: E <sup>h</sup> = Hg mass emissions for the hour, (lb); K = Units conversion constant, 6.24 × 10 −11 lb-scm/μgm-scf; C <sup>h</sup> = Hourly Hg concentration, dry basis, (μgm/dscm); Q <sup>h</sup> = Hourly stack gas volumetric flow rate, (scfh); t <sup>h</sup> = Unit operating time, *i.e.* , the fraction of the hour for which the unit operated; and B <sup>ws</sup> = Stack gas moisture content, expressed as a decimal fraction ( *e.g.* , for 8 percent H <sup>2</sup> O, B <sup>ws</sup> = 0.08).
(C)Use Equation 8, below, to calculate M, the total mass of Hg emitted for the month, by summing the hourly masses derived from Equation 6 or 7 (as applicable): ER13JN07.019 Where: M = Total Hg mass emissions for the month, (lb); E <sup>h</sup> = Hg mass emissions for hour “h”, from Equation 6 or 7 of this section, (lb); and n = Number of unit operating hours in the month with valid CE and electrical output data, excluding hours of unit startup, shutdown and malfunction.
(ii)Calculate the monthly Hg emission rate on an output basis (lb/MWh) using Equation 9, below. For a cogeneration unit, use Equation 5 in paragraph
(g)of this section instead. ER13JN07.020 Where: ER = Monthly Hg emission rate, (lb/MWh); M = Total mass of Hg emissions for the month, from Equation 8, above, (lb); and P = Total electrical output for the month, for the hours used to calculate M, (MWh).
(iii)Until 12 monthly Hg emission rates have been accumulated, calculate and report only the monthly averages. Then, for each subsequent calendar month, use Equation 10 below to calculate the 12-month rolling average as a weighted average of the Hg emission rate for the current month and the Hg emission rates for the previous 11 months, with one exception. Calendar months in which the unit does not operate (zero unit operating hours) shall not be included in the 12-month rolling average. ER13JN07.021 Where: E <sup>avg</sup> = Weighted 12-month rolling average Hg emission rate, (lb/MWh); ER <sup>i</sup> = Monthly Hg emission rate, for month “i”, (lb/MWh); and n = Number of unit operating hours in month “i” with valid CEM and electrical output data, excluding hours of unit startup, shutdown, and malfunction.
(3)If a sorbent trap monitoring system is used in lieu of a Hg CEMS, as described in § 75.15 of this chapter and in appendix K to part 75 of this chapter, calculate the monthly Hg emission rates using Equations 7 through 9 of this section, except that for a particular pair of sorbent traps, C <sup>h</sup> in Equation 7 shall be the flow-proportional average Hg concentration measured over the data collection period.
(i)Daily calibration drift
(CD)tests and quarterly accuracy determinations shall be performed for Hg CEMS in accordance with Procedure 1 of appendix F to this part. For the CD assessments, you may use either elemental mercury or mercuric chloride (Hg° HgCl <sup>2</sup> ) standards. The four quarterly accuracy determinations shall consist of one RATA and three measurement error
(ME)tests using HgCl <sup>2</sup> standards, as described in section 8.3 of Performance Specification 12-A in appendix B to this part (note: Hg° standards may be used if the Hg monitor does not have a converter). Alternatively, the owner or operator may implement the applicable daily, weekly, quarterly, and annual quality assurance
(QA)requirements for Hg CEMS in appendix B to part 75 of this chapter, in lieu of the QA procedures in appendices B and F to this part. Annual RATA of sorbent trap monitoring systems shall be performed in accordance with appendices A and B to part 75 of this chapter, and all other quality assurance requirements specified in appendix K to part 75 of this chapter shall be met for sorbent trap monitoring systems. § 60.51Da Reporting requirements.
(a)For SO <sup>2</sup> , NO <sup>X</sup> , PM, and Hg emissions, the performance test data from the initial and subsequent performance test and from the performance evaluation of the continuous monitors (including the transmissometer) are submitted to the Administrator.
(b)For SO <sup>2</sup> and NO <sup>X</sup> the following information is reported to the Administrator for each 24-hour period.
(1)Calendar date.
(2)The average SO <sup>2</sup> and NO <sup>X</sup> emission rates (ng/J or lb/MMBtu) for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for non-compliance with the emission standards; and, description of corrective actions taken.
(3)Percent reduction of the potential combustion concentration of SO <sup>2</sup> for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for non-compliance with the standard; and, description of corrective actions taken.
(4)Identification of the boiler operating days for which pollutant or diluent data have not been obtained by an approved method for at least 75 percent of the hours of operation of the facility; justification for not obtaining sufficient data; and description of corrective actions taken.
(5)Identification of the times when emissions data have been excluded from the calculation of average emission rates because of startup, shutdown, malfunction (NO <sup>X</sup> only), emergency conditions (SO <sup>2</sup> only), or other reasons, and justification for excluding data for reasons other than startup, shutdown, malfunction, or emergency conditions.
(6)Identification of “F” factor used for calculations, method of determination, and type of fuel combusted.
(7)Identification of times when hourly averages have been obtained based on manual sampling methods.
(8)Identification of the times when the pollutant concentration exceeded full span of the CEMS.
(9)Description of any modifications to CEMS which could affect the ability of the CEMS to comply with Performance Specifications 2 or 3.
(c)If the minimum quantity of emission data as required by § 60.49Da is not obtained for any 30 successive boiler operating days, the following information obtained under the requirements of § 60.48Da(h) is reported to the Administrator for that 30-day period:
(1)The number of hourly averages available for outlet emission rates
(no)and inlet emission rates (n <sup>i</sup> ) as applicable.
(2)The standard deviation of hourly averages for outlet emission rates (s <sup>o</sup> ) and inlet emission rates (s <sup>i</sup> ) as applicable.
(3)The lower confidence limit for the mean outlet emission rate (E <sup>o</sup> *) and the upper confidence limit for the mean inlet emission rate (E <sup>i</sup> *) as applicable.
(4)The applicable potential combustion concentration.
(5)The ratio of the upper confidence limit for the mean outlet emission rate (E <sup>o</sup> *) and the allowable emission rate (E <sup>std</sup> ) as applicable.
(d)If any standards under § 60.43Da are exceeded during emergency conditions because of control system malfunction, the owner or operator of the affected facility shall submit a signed statement:
(1)Indicating if emergency conditions existed and requirements under § 60.48Da(d) were met during each period, and
(2)Listing the following information:
(i)Time periods the emergency condition existed;
(ii)Electrical output and demand on the owner or operator's electric utility system and the affected facility;
(iii)Amount of power purchased from interconnected neighboring utility companies during the emergency period;
(iv)Percent reduction in emissions achieved;
(v)Atmospheric emission rate (ng/J) of the pollutant discharged; and
(vi)Actions taken to correct control system malfunction.
(e)If fuel pretreatment credit toward the SO <sup>2</sup> emission standard under § 60.43Da is claimed, the owner or operator of the affected facility shall submit a signed statement:
(1)Indicating what percentage cleaning credit was taken for the calendar quarter, and whether the credit was determined in accordance with the provisions of § 60.50Da and Method 19 of appendix A of this part; and
(2)Listing the quantity, heat content, and date each pretreated fuel shipment was received during the previous quarter; the name and location of the fuel pretreatment facility; and the total quantity and total heat content of all fuels received at the affected facility during the previous quarter.
(f)For any periods for which opacity, SO <sup>2</sup> or NO <sup>X</sup> emissions data are not available, the owner or operator of the affected facility shall submit a signed statement indicating if any changes were made in operation of the emission control system during the period of data unavailability. Operations of the control system and affected facility during periods of data unavailability are to be compared with operation of the control system and affected facility before and following the period of data unavailability.
(g)For Hg, the following information shall be reported to the Administrator:
(1)Company name and address;
(2)Date of report and beginning and ending dates of the reporting period;
(3)The applicable Hg emission limit (lb/MWh); and
(4)For each month in the reporting period:
(i)The number of unit operating hours;
(ii)The number of unit operating hours with valid data for Hg concentration, stack gas flow rate, moisture (if required), and electrical output;
(iii)The monthly Hg emission rate (lb/MWh);
(iv)The number of hours of valid data excluded from the calculation of the monthly Hg emission rate, due to unit startup, shutdown and malfunction; and
(v)The 12-month rolling average Hg emission rate (lb/MWh); and
(5)The data assessment report
(DAR)required by appendix F to this part, or an equivalent summary of QA test results if the QA of part 75 of this chapter are implemented.
(h)The owner or operator of the affected facility shall submit a signed statement indicating whether:
(1)The required CEMS calibration, span, and drift checks or other periodic audits have or have not been performed as specified.
(2)The data used to show compliance was or was not obtained in accordance with approved methods and procedures of this part and is representative of plant performance.
(3)The minimum data requirements have or have not been met; or, the minimum data requirements have not been met for errors that were unavoidable.
(4)Compliance with the standards has or has not been achieved during the reporting period.
(i)For the purposes of the reports required under § 60.7, periods of excess emissions are defined as all 6-minute periods during which the average opacity exceeds the applicable opacity standards under § 60.42Da(b). Opacity levels in excess of the applicable opacity standard and the date of such excesses are to be submitted to the Administrator each calendar quarter.
(j)The owner or operator of an affected facility shall submit the written reports required under this section and subpart A to the Administrator semiannually for each six-month period. All semiannual reports shall be postmarked by the 30th day following the end of each six-month period.
(k)The owner or operator of an affected facility may submit electronic quarterly reports for SO <sup>2</sup> and/or NO <sup>X</sup> and/or opacity and/or Hg in lieu of submitting the written reports required under paragraphs (b), (g), and
(i)of this section. The format of each quarterly electronic report shall be coordinated with the permitting authority. The electronic report(s) shall be submitted no later than 30 days after the end of the calendar quarter and shall be accompanied by a certification statement from the owner or operator, indicating whether compliance with the applicable emission standards and minimum data requirements of this subpart was achieved during the reporting period. Before submitting reports in the electronic format, the owner or operator shall coordinate with the permitting authority to obtain their agreement to submit reports in this alternative format. § 60.52Da Recordkeeping requirements. The owner or operator of an affected facility subject to the emissions limitations in § 60.45Da shall provide notifications in accordance with § 60.7(a) and shall maintain records of all information needed to demonstrate compliance including performance tests, monitoring data, fuel analyses, and calculations, consistent with the requirements of § 60.7(f). Subpart Db—[Amended] 5. Subpart Db is revised to read as follows Subpart Db—Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units Sec. 60.40b Applicability and delegation of authority. 60.41b Definitions. 60.42b Standard for sulfur dioxide (SO <sup>2</sup> ). 60.43b Standard for particulate matter (PM). 60.44b Standard for nitrogen oxides (NO <sup>X</sup> ). 60.45b Compliance and performance test methods and procedures for sulfur dioxide. 60.46b Compliance and performance test methods and procedures for particulate matter and nitrogen oxides. 60.47b Emission monitoring for sulfur dioxide. 60.48b Emission monitoring for particulate matter and nitrogen oxides. 60.49b Reporting and recordkeeping requirements. Subpart Db—Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units § 60.40b Applicability and delegation of authority.
(a)The affected facility to which this subpart applies is each steam generating unit that commences construction, modification, or reconstruction after June 19, 1984, and that has a heat input capacity from fuels combusted in the steam generating unit of greater than 29 megawatts
(MW)(100 million British thermal units per hour (MMBtu/hr)).
(b)Any affected facility meeting the applicability requirements under paragraph
(a)of this section and commencing construction, modification, or reconstruction after June 19, 1984, but on or before June 19, 1986, is subject to the following standards:
(1)Coal-fired affected facilities having a heat input capacity between 29 and 73 MW (100 and 250 MMBtu/hr), inclusive, are subject to the particulate matter
(PM)and nitrogen oxides (NO <sup>X</sup> ) standards under this subpart.
(2)Coal-fired affected facilities having a heat input capacity greater than 73 MW (250 MMBtu/hr) and meeting the applicability requirements under subpart D (Standards of performance for fossil-fuel-fired steam generators; § 60.40) are subject to the PM and NO <sup>X</sup> standards under this subpart and to the sulfur dioxide (SO <sup>2</sup> ) standards under subpart D (§ 60.43).
(3)Oil-fired affected facilities having a heat input capacity between 29 and 73 MW (100 and 250 MMBtu/hr), inclusive, are subject to the NO <sup>X</sup> standards under this subpart.
(4)Oil-fired affected facilities having a heat input capacity greater than 73 MW (250 MMBtu/hr) and meeting the applicability requirements under subpart D (Standards of performance for fossil-fuel-fired steam generators; § 60.40) are also subject to the NO <sup>X</sup> standards under this subpart and the PM and SO <sup>2</sup> standards under subpart D (§ 60.42 and § 60.43).
(c)Affected facilities that also meet the applicability requirements under subpart J (Standards of performance for petroleum refineries; § 60.104) are subject to the PM and NO <sup>X</sup> standards under this subpart and the SO <sup>2</sup> standards under subpart J (§ 60.104).
(d)Affected facilities that also meet the applicability requirements under subpart E (Standards of performance for incinerators; § 60.50) are subject to the NO <sup>X</sup> and PM standards under this subpart.
(e)Steam generating units meeting the applicability requirements under subpart Da (Standards of performance for electric utility steam generating units; § 60.40Da) are not subject to this subpart.
(f)Any change to an existing steam generating unit for the sole purpose of combusting gases containing total reduced sulfur
(TRS)as defined under § 60.281 is not considered a modification under § 60.14 and the steam generating unit is not subject to this subpart.
(g)In delegating implementation and enforcement authority to a State under section 111(c) of the Clean Air Act, the following authorities shall be retained by the Administrator and not transferred to a State.
(1)Section 60.44b(f).
(2)Section 60.44b(g).
(3)Section 60.49b(a)(4).
(h)Any affected facility that meets the applicability requirements and is subject to subpart Ea, subpart Eb, or subpart AAAA of this part is not covered by this subpart.
(i)Heat recovery steam generators that are associated with combined cycle gas turbines and that meet the applicability requirements of subpart GG or KKKK of this part are not subject to this subpart. This subpart will continue to apply to all other heat recovery steam generators that are capable of combusting more than 29 MW (100 MMBtu/hr) heat input of fossil fuel. If the heat recovery steam generator is subject to this subpart, only emissions resulting from combustion of fuels in the steam generating unit are subject to this subpart. (The gas turbine emissions are subject to subpart GG or KKKK, as applicable, of this part.)
(j)Any affected facility meeting the applicability requirements under paragraph
(a)of this section and commencing construction, modification, or reconstruction after June 19, 1986 is not subject to subpart D (Standards of Performance for Fossil-Fuel-Fired Steam Generators, § 60.40).
(k)Any affected facility that meets the applicability requirements and is subject to an EPA approved State or Federal section 111(d)/129 plan implementing subpart Cb or subpart BBBB of this part is not covered by this subpart. § 60.41b Definitions. As used in this subpart, all terms not defined herein shall have the meaning given them in the Clean Air Act and in subpart A of this part. *Annual capacity factor* means the ratio between the actual heat input to a steam generating unit from the fuels listed in § 60.42b(a), § 60.43b(a), or § 60.44b(a), as applicable, during a calendar year and the potential heat input to the steam generating unit had it been operated for 8,760 hours during a calendar year at the maximum steady state design heat input capacity. In the case of steam generating units that are rented or leased, the actual heat input shall be determined based on the combined heat input from all operations of the affected facility in a calendar year. *Byproduct/waste* means any liquid or gaseous substance produced at chemical manufacturing plants, petroleum refineries, or pulp and paper mills (except natural gas, distillate oil, or residual oil) and combusted in a steam generating unit for heat recovery or for disposal. Gaseous substances with carbon dioxide (CO <sup>2</sup> ) levels greater than 50 percent or carbon monoxide levels greater than 10 percent are not byproduct/waste for the purpose of this subpart. *Chemical manufacturing plants* mean industrial plants that are classified by the Department of Commerce under Standard Industrial Classification
(SIC)Code 28. *Coal* means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17), coal refuse, and petroleum coke. Coal-derived synthetic fuels, including but not limited to solvent refined coal, gasified coal, coal-oil mixtures, coke oven gas, and coal-water mixtures, are also included in this definition for the purposes of this subpart. *Coal refuse* means any byproduct of coal mining or coal cleaning operations with an ash content greater than 50 percent, by weight, and a heating value less than 13,900 kJ/kg (6,000 Btu/lb) on a dry basis. *Cogeneration* , also known as combined heat and power, means a facility that simultaneously produces both electric (or mechanical) and useful thermal energy from the same primary energy source. *Coke oven gas* means the volatile constituents generated in the gaseous exhaust during the carbonization of bituminous coal to form coke. *Combined cycle system* means a system in which a separate source, such as a gas turbine, internal combustion engine, kiln, etc., provides exhaust gas to a steam generating unit. *Conventional technology* means wet flue gas desulfurization
(FGD)technology, dry FGD technology, atmospheric fluidized bed combustion technology, and oil hydrodesulfurization technology. *Distillate oil* means fuel oils that contain 0.05 weight percent nitrogen or less and comply with the specifications for fuel oil numbers 1 and 2, as defined by the American Society of Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17). *Dry flue gas desulfurization technology* means a SO <sup>2</sup> control system that is located downstream of the steam generating unit and removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline reagent and water, whether introduced separately or as a premixed slurry or solution and forming a dry powder material. This definition includes devices where the dry powder material is subsequently converted to another form. Alkaline slurries or solutions used in dry flue gas desulfurization technology include but are not limited to lime and sodium. *Duct burner* means a device that combusts fuel and that is placed in the exhaust duct from another source, such as a stationary gas turbine, internal combustion engine, kiln, etc., to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a steam generating unit. *Emerging technology* means any SO <sup>2</sup> control system that is not defined as a conventional technology under this section, and for which the owner or operator of the facility has applied to the Administrator and received approval to operate as an emerging technology under § 60.49b(a)(4). *Federally enforceable* means all limitations and conditions that are enforceable by the Administrator, including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State Implementation Plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 51.24. *Fluidized bed combustion technology* means combustion of fuel in a bed or series of beds (including but not limited to bubbling bed units and circulating bed units) of limestone aggregate (or other sorbent materials) in which these materials are forced upward by the flow of combustion air and the gaseous products of combustion. *Fuel pretreatment* means a process that removes a portion of the sulfur in a fuel before combustion of the fuel in a steam generating unit. *Full capacity* means operation of the steam generating unit at 90 percent or more of the maximum steady-state design heat input capacity. *Gaseous fuel* means any fuel that is present as a gas at ISO conditions. *Gross output* means the gross useful work performed by the steam generated. For units generating only electricity, the gross useful work performed is the gross electrical output from the turbine/generator set. For cogeneration units, the gross useful work performed is the gross electrical or mechanical output plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output (i.e., steam delivered to an industrial process). *Heat input* means heat derived from combustion of fuel in a steam generating unit and does not include the heat derived from preheated combustion air, recirculated flue gases, or exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc. *Heat release rate* means the steam generating unit design heat input capacity (in MW or Btu/hr) divided by the furnace volume (in cubic meters or cubic feet); the furnace volume is that volume bounded by the front furnace wall where the burner is located, the furnace side waterwall, and extending to the level just below or in front of the first row of convection pass tubes. *Heat transfer medium* means any material that is used to transfer heat from one point to another point. *High heat release rate* means a heat release rate greater than 730,000 J/sec-m 3 (70,000 Btu/hr-ft 3 ). *ISO Conditions* means a temperature of 288 Kelvin, a relative humidity of 60 percent, and a pressure of 101.3 kilopascals. *Lignite* means a type of coal classified as lignite A or lignite B by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17). *Low heat release rate* means a heat release rate of 730,000 J/sec-m 3 (70,000 Btu/hr-ft 3 ) or less. *Mass-feed stoker steam generating unit* means a steam generating unit where solid fuel is introduced directly into a retort or is fed directly onto a grate where it is combusted. *Maximum heat input capacity* means the ability of a steam generating unit to combust a stated maximum amount of fuel on a steady state basis, as determined by the physical design and characteristics of the steam generating unit. *Municipal-type solid waste* means refuse, more than 50 percent of which is waste consisting of a mixture of paper, wood, yard wastes, food wastes, plastics, leather, rubber, and other combustible materials, and noncombustible materials such as glass and rock. *Natural gas* means:
(1)A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal constituent is methane; or
(2)liquefied petroleum gas, as defined by the American Society for Testing and Materials in ASTM D1835 (incorporated by reference, see § 60.17). *Noncontinental area* means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern Mariana Islands. *Oil* means crude oil or petroleum or a liquid fuel derived from crude oil or petroleum, including distillate and residual oil. *Petroleum refinery* means industrial plants as classified by the Department of Commerce under Standard Industrial Classification
(SIC)Code 29. *Potential sulfur dioxide emission rate* means the theoretical SO <sup>2</sup> emissions (nanograms per joule (ng/J) or lb/MMBtu heat input) that would result from combusting fuel in an uncleaned state and without using emission control systems. *Process heater* means a device that is primarily used to heat a material to initiate or promote a chemical reaction in which the material participates as a reactant or catalyst. *Pulp and paper mills* means industrial plants that are classified by the Department of Commerce under North American Industry Classification System (NAICS) Code 322 or Standard Industrial Classification
(SIC)Code 26. *Pulverized coal-fired steam generating unit* means a steam generating unit in which pulverized coal is introduced into an air stream that carries the coal to the combustion chamber of the steam generating unit where it is fired in suspension. This includes both conventional pulverized coal-fired and micropulverized coal-fired steam generating units. Residual oil means crude oil, fuel oil numbers 1 and 2 that have a nitrogen content greater than 0.05 weight percent, and all fuel oil numbers 4, 5 and 6, as defined by the American Society of Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17). *Spreader stoker steam generating unit* means a steam generating unit in which solid fuel is introduced to the combustion zone by a mechanism that throws the fuel onto a grate from above. Combustion takes place both in suspension and on the grate. *Steam generating unit* means a device that combusts any fuel or byproduct/waste and produces steam or heats water or any other heat transfer medium. This term includes any municipal-type solid waste incinerator with a heat recovery steam generating unit or any steam generating unit that combusts fuel and is part of a cogeneration system or a combined cycle system. This term does not include process heaters as they are defined in this subpart. *Steam generating unit operating day* means a 24-hour period between 12:00 midnight and the following midnight during which any fuel is combusted at any time in the steam generating unit. It is not necessary for fuel to be combusted continuously for the entire 24-hour period. *Very low sulfur oil* means for units constructed, reconstructed, or modified on or before February 28, 2005, an oil that contains no more than 0.5 weight percent sulfur or that, when combusted without SO <sup>2</sup> emission control, has a SO <sup>2</sup> emission rate equal to or less than 215 ng/J (0.5 lb/MMBtu) heat input. For units constructed, reconstructed, or modified after February 28, 2005, *very low sulfur oil* means an oil that contains no more than 0.3 weight percent sulfur or that, when combusted without SO <sup>2</sup> emission control, has a SO <sup>2</sup> emission rate equal to or less than 140 ng/J (0.32 lb/MMBtu) heat input. *Wet flue gas desulfurization technology* means a SO <sup>2</sup> control system that is located downstream of the steam generating unit and removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gas with an alkaline slurry or solution and forming a liquid material. This definition applies to devices where the aqueous liquid material product of this contact is subsequently converted to other forms. Alkaline reagents used in wet flue gas desulfurization technology include, but are not limited to, lime, limestone, and sodium. *Wet scrubber system* means any emission control device that mixes an aqueous stream or slurry with the exhaust gases from a steam generating unit to control emissions of PM or SO <sup>2</sup> . *Wood* means wood, wood residue, bark, or any derivative fuel or residue thereof, in any form, including, but not limited to, sawdust, sanderdust, wood chips, scraps, slabs, millings, shavings, and processed pellets made from wood or other forest residues. § 60.42b Standard for sulfur dioxide (SO 2 ).
(a)Except as provided in paragraphs (b), (c), (d), or
(k)of this section, on and after the date on which the performance test is completed or required to be completed under § 60.8, whichever comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, that combusts coal or oil shall cause to be discharged into the atmosphere any gases that contain SO <sup>2</sup> in excess of 87 ng/J (0.20 lb/MMBtu) or 10 percent (0.10) of the potential SO <sup>2</sup> emission rate (90 percent reduction) and the emission limit determined according to the following formula: ER13JN07.022 Where: E <sup>s</sup> = SO <sup>2</sup> emission limit, in ng/J or lb/MMBtu heat input; K <sup>a</sup> = 520 ng/J (or 1.2 lb/MMBtu); K <sup>b</sup> = 340 ng/J (or 0.80 lb/MMBtu); H <sup>a</sup> = Heat input from the combustion of coal, in J (MMBtu); and H <sup>b</sup> = Heat input from the combustion of oil, in J (MMBtu). Only the heat input supplied to the affected facility from the combustion of coal and oil is counted under this section. No credit is provided for the heat input to the affected facility from the combustion of natural gas, wood, municipal-type solid waste, or other fuels or heat derived from exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc.
(b)On and after the date on which the performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, that combusts coal refuse alone in a fluidized bed combustion steam generating unit shall cause to be discharged into the atmosphere any gases that contain SO <sup>2</sup> in excess of 87 ng/J (0.20 lb/MMBtu) or 20 percent (0.20) of the potential SO <sup>2</sup> emission rate (80 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input. If coal or oil is fired with coal refuse, the affected facility is subject to paragraph
(a)or
(d)of this section, as applicable.
(c)On and after the date on which the performance test is completed or is required to be completed under § 60.8, whichever comes first, no owner or operator of an affected facility that combusts coal or oil, either alone or in combination with any other fuel, and that uses an emerging technology for the control of SO <sup>2</sup> emissions, shall cause to be discharged into the atmosphere any gases that contain SO <sup>2</sup> in excess of 50 percent of the potential SO <sup>2</sup> emission rate (50 percent reduction) and that contain SO <sup>2</sup> in excess of the emission limit determined according to the following formula: ER13JN07.023 Where: E <sup>s</sup> = SO <sup>2</sup> emission limit, in ng/J or lb/MM Btu heat input; K <sup>c</sup> = 260 ng/J (or 0.60 lb/MMBtu); K <sup>d</sup> = 170 ng/J (or 0.40 lb/MMBtu); H <sup>c</sup> = Heat input from the combustion of coal, in J (MMBtu); and H <sup>d</sup> = Heat input from the combustion of oil, in J (MMBtu). Only the heat input supplied to the affected facility from the combustion of coal and oil is counted under this section. No credit is provided for the heat input to the affected facility from the combustion of natural gas, wood, municipal-type solid waste, or other fuels, or from the heat input derived from exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc.
(d)On and after the date on which the performance test is completed or required to be completed under § 60.8, whichever comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005 and listed in paragraphs (d)(1), (2), (3), or
(4)of this section shall cause to be discharged into the atmosphere any gases that contain SO <sup>2</sup> in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the affected facility combusts coal, or 215 ng/J (0.5 lb/MMBtu) heat input if the affected facility combusts oil other than very low sulfur oil. Percent reduction requirements are not applicable to affected facilities under paragraphs (d)(1), (2),
(3)or
(4)of this section.
(1)Affected facilities that have an annual capacity factor for coal and oil of 30 percent (0.30) or less and are subject to a federally enforceable permit limiting the operation of the affected facility to an annual capacity factor for coal and oil of 30 percent (0.30) or less;
(2)Affected facilities located in a noncontinental area; or
(3)Affected facilities combusting coal or oil, alone or in combination with any fuel, in a duct burner as part of a combined cycle system where 30 percent (0.30) or less of the heat entering the steam generating unit is from combustion of coal and oil in the duct burner and 70 percent (0.70) or more of the heat entering the steam generating unit is from the exhaust gases entering the duct burner; or
(4)The affected facility burns coke oven gas alone or in combination with natural gas or very low sulfur distillate oil.
(e)Except as provided in paragraph
(f)of this section, compliance with the emission limits, fuel oil sulfur limits, and/or percent reduction requirements under this section are determined on a 30-day rolling average basis.
(f)Except as provided in paragraph (j)(2) of this section, compliance with the emission limits or fuel oil sulfur limits under this section is determined on a 24-hour average basis for affected facilities that
(1)have a federally enforceable permit limiting the annual capacity factor for oil to 10 percent or less,
(2)combust only very low sulfur oil, and
(3)do not combust any other fuel.
(g)Except as provided in paragraph
(i)of this section and § 60.45b(a), the SO <sup>2</sup> emission limits and percent reduction requirements under this section apply at all times, including periods of startup, shutdown, and malfunction.
(h)Reductions in the potential SO <sup>2</sup> emission rate through fuel pretreatment are not credited toward the percent reduction requirement under paragraph
(c)of this section unless:
(1)Fuel pretreatment results in a 50 percent or greater reduction in potential SO <sup>2</sup> emissions and
(2)Emissions from the pretreated fuel (without combustion or post-combustion SO <sup>2</sup> control) are equal to or less than the emission limits specified in paragraph
(c)of this section.
(i)An affected facility subject to paragraph (a), (b), or
(c)of this section may combust very low sulfur oil or natural gas when the SO <sup>2</sup> control system is not being operated because of malfunction or maintenance of the SO <sup>2</sup> control system.
(j)Percent reduction requirements are not applicable to affected facilities combusting only very low sulfur oil. The owner or operator of an affected facility combusting very low sulfur oil shall demonstrate that the oil meets the definition of very low sulfur oil by:
(1)Following the performance testing procedures as described in § 60.45b(c) or § 60.45b(d), and following the monitoring procedures as described in § 60.47b(a) or § 60.47b(b) to determine SO <sup>2</sup> emission rate or fuel oil sulfur content; or
(2)maintaining fuel records as described in § 60.49b(r). (k)(1) Except as provided in paragraphs (k)(2), (k)(3), and (k)(4) of this section, on and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commences construction, reconstruction, or modification after February 28, 2005, and that combusts coal, oil, natural gas, a mixture of these fuels, or a mixture of these fuels with any other fuels shall cause to be discharged into the atmosphere any gases that contain SO <sup>2</sup> in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 8 percent (0.08) of the potential SO <sup>2</sup> emission rate (92 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input.
(2)Units firing only very low sulfur oil and/or a mixture of gaseous fuels with a potential SO <sup>2</sup> emission rate of 140 ng/J (0.32 lb/MMBtu) heat input or less are exempt from the SO <sup>2</sup> emissions limit in paragraph 60.42b(k)(1).
(3)Units that are located in a noncontinental area and that combust coal or oil shall not discharge any gases that contain SO <sup>2</sup> in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the affected facility combusts coal, or 215 ng/J (0.50 lb/MMBtu) heat input if the affected facility combusts oil.
(4)As an alternative to meeting the requirements under paragraph (k)(1) of this section, modified facilities that combust coal or a mixture of coal with other fuels shall not cause to be discharged into the atmosphere any gases that contain SO <sup>2</sup> in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO <sup>2</sup> emission rate (90 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input. § 60.43b Standard for particulate matter (PM).
(a)On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005 that combusts coal or combusts mixtures of coal with other fuels, shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of the following emission limits:
(1)22 ng/J (0.051 lb/MMBtu) heat input,
(i)If the affected facility combusts only coal, or
(ii)If the affected facility combusts coal and other fuels and has an annual capacity factor for the other fuels of 10 percent (0.10) or less.
(2)43 ng/J (0.10 lb/MMBtu) heat input if the affected facility combusts coal and other fuels and has an annual capacity factor for the other fuels greater than 10 percent (0.10) and is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor greater than 10 percent (0.10) for fuels other than coal.
(3)86 ng/J (0.20 lb/MMBtu) heat input if the affected facility combusts coal or coal and other fuels and
(i)Has an annual capacity factor for coal or coal and other fuels of 30 percent (0.30) or less,
(ii)Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or less,
(iii)Has a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor of 30 percent (0.30) or less for coal or coal and other solid fuels, and
(iv)Construction of the affected facility commenced after June 19, 1984, and before November 25, 1986.
(4)An affected facility burning coke oven gas alone or in combination with other fuels not subject to a PM standard under § 60.43b and not using a post-combustion technology (except a wet scrubber) for reducing PM or SO <sup>2</sup> emissions is not subject to the PM limits under § 60.43b(a).
(b)On and after the date on which the performance test is completed or required to be completed under § 60.8, whichever comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, and that combusts oil (or mixtures of oil with other fuels) and uses a conventional or emerging technology to reduce SO <sup>2</sup> emissions shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.
(c)On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, and that combusts wood, or wood with other fuels, except coal, shall cause to be discharged from that affected facility any gases that contain PM in excess of the following emission limits:
(1)43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has an annual capacity factor greater than 30 percent (0.30) for wood.
(2)86 ng/J (0.20 lb/MMBtu) heat input if
(i)The affected facility has an annual capacity factor of 30 percent (0.30) or less for wood;
(ii)Is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor of 30 percent (0.30) or less for wood; and
(iii)Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or less.
(d)On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that combusts municipal-type solid waste or mixtures of municipal-type solid waste with other fuels, shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of the following emission limits:
(1)43 ng/J (0.10 lb/MMBtu) heat input;
(i)If the affected facility combusts only municipal-type solid waste; or
(ii)If the affected facility combusts municipal-type solid waste and other fuels and has an annual capacity factor for the other fuels of 10 percent (0.10) or less.
(2)86 ng/J (0.20 lb/MMBtu) heat input if the affected facility combusts municipal-type solid waste or municipal-type solid waste and other fuels; and
(i)Has an annual capacity factor for municipal-type solid waste and other fuels of 30 percent (0.30) or less;
(ii)Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or less;
(iii)Has a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor of 30 percent (0.30) or less for municipal-type solid waste, or municipal-type solid waste and other fuels; and
(iv)Construction of the affected facility commenced after June 19, 1984, but on or before November 25, 1986.
(e)For the purposes of this section, the annual capacity factor is determined by dividing the actual heat input to the steam generating unit during the calendar year from the combustion of coal, wood, or municipal-type solid waste, and other fuels, as applicable, by the potential heat input to the steam generating unit if the steam generating unit had been operated for 8,760 hours at the maximum heat input capacity.
(f)On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that combusts coal, oil, wood, or mixtures of these fuels with any other fuels shall cause to be discharged into the atmosphere any gases that exhibit greater than 20 percent opacity (6-minute average), except for one 6-minute period per hour of not more than 27 percent opacity.
(g)The PM and opacity standards apply at all times, except during periods of startup, shutdown or malfunction. (h)(1) Except as provided in paragraphs (h)(2), (h)(3), (h)(4), and (h)(5) of this section, on and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after February 28, 2005, and that combusts coal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input,
(2)As an alternative to meeting the requirements of paragraph (h)(1) of this section, the owner or operator of an affected facility for which modification commenced after February 28, 2005, may elect to meet the requirements of this paragraph. On and after the date on which the initial performance test is completed or required to be completed under § 60.8, no owner or operator of an affected facility that commences modification after February 28, 2005 shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of both:
(i)22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion of coal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels; and
(ii)0.2 percent of the combustion concentration (99.8 percent reduction) when combusting coal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels.
(3)On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commences modification after February 28, 2005, and that combusts over 30 percent wood (by heat input) on an annual basis and has a maximum heat input capacity of 73 MW (250 MMBtu/h) or less shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.
(4)On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commences modification after February 28, 2005, and that combusts over 30 percent wood (by heat input) on an annual basis and has a maximum heat input capacity greater than 73 MW (250 MMBtu/h) shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 37 ng/J (0.085 lb/MMBtu) heat input.
(5)On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, an owner or operator of an affected facility that commences construction, reconstruction, or modification after February 28, 2005, and that combusts only oil that contains no more than 0.3 weight percent sulfur, coke oven gas, a mixture of these fuels, or either fuel (or a mixture of these fuels) in combination with other fuels not subject to a PM standard under § 60.43b and not using a post-combustion technology (except a wet scrubber) to reduce SO <sup>2</sup> or PM emissions is not subject to the PM limits under § 60.43b(h)(1). § 60.44b Standard for nitrogen oxides (NO X ).
(a)Except as provided under paragraphs
(k)and
(l)of this section, on and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that is subject to the provisions of this section and that combusts only coal, oil, or natural gas shall cause to be discharged into the atmosphere from that affected facility any gases that contain NO <sup>X</sup> (expressed as NO <sup>2</sup> ) in excess of the following emission limits: Fuel/steam generating unit type Nitrogen oxide emission limits (expressed as NO <sup>2</sup> ) heat input ng/J lb/MMBTu
(1)Natural gas and distillate oil, except (4):
(i)Low heat release rate 43 0.10
(ii)High heat release rate 86 0.20
(2)Residual oil:
(i)Low heat release rate 130 0.30
(ii)High heat release rate 170 0.40
(3)Coal:
(i)Mass-feed stoker 210 0.50
(ii)Spreader stoker and fluidized bed combustion 260 0.60
(iii)Pulverized coal 300 0.70
(iv)Lignite, except
(v)260 0.60
(v)Lignite mined in North Dakota, South Dakota, or Montana and combusted in a slag tap furnace 340 0.80
(vi)Coal-derived synthetic fuels 210 0.50
(4)Duct burner used in a combined cycle system:
(i)Natural gas and distillate oil 86 0.20
(ii)Residual oil 170 0.40
(b)Except as provided under paragraphs
(k)and
(l)of this section, on and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that simultaneously combusts mixtures of coal, oil, or natural gas shall cause to be discharged into the atmosphere from that affected facility any gases that contain NO <sup>X</sup> in excess of a limit determined by the use of the following formula: ER13JN07.024 Where: E <sup>n</sup> = NO <sup>X</sup> emission limit (expressed as NO <sup>2</sup> ), ng/J (lb/MMBtu); EL <sup>go</sup> = Appropriate emission limit from paragraph (a)(1) for combustion of natural gas or distillate oil, ng/J (lb/MMBtu); H <sup>go</sup> = Heat input from combustion of natural gas or distillate oil, J (MMBtu); EL <sup>ro</sup> = Appropriate emission limit from paragraph (a)(2) for combustion of residual oil, ng/J (lb/MMBtu); H <sup>ro</sup> = Heat input from combustion of residual oil, J (MMBtu); EL <sup>c</sup> = Appropriate emission limit from paragraph (a)(3) for combustion of coal, ng/J (lb/MMBtu); and H <sup>c</sup> = Heat input from combustion of coal, J (MMBtu).
(c)Except as provided under paragraph
(l)of this section, on and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that simultaneously combusts coal or oil, or a mixture of these fuels with natural gas, and wood, municipal-type solid waste, or any other fuel shall cause to be discharged into the atmosphere any gases that contain NO <sup>X</sup> in excess of the emission limit for the coal or oil, or mixtures of these fuels with natural gas combusted in the affected facility, as determined pursuant to paragraph
(a)or
(b)of this section, unless the affected facility has an annual capacity factor for coal or oil, or mixture of these fuels with natural gas of 10 percent (0.10) or less and is subject to a federally enforceable requirement that limits operation of the affected facility to an annual capacity factor of 10 percent (0.10) or less for coal, oil, or a mixture of these fuels with natural gas.
(d)On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that simultaneously combusts natural gas with wood, municipal-type solid waste, or other solid fuel, except coal, shall cause to be discharged into the atmosphere from that affected facility any gases that contain NO <sup>X</sup> in excess of 130 ng/J (0.30 lb/MMBtu) heat input unless the affected facility has an annual capacity factor for natural gas of 10 percent (0.10) or less and is subject to a federally enforceable requirement that limits operation of the affected facility to an annual capacity factor of 10 percent (0.10) or less for natural gas.
(e)Except as provided under paragraph
(l)of this section, on and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that simultaneously combusts coal, oil, or natural gas with byproduct/waste shall cause to be discharged into the atmosphere any gases that contain NO <sup>X</sup> in excess of the emission limit determined by the following formula unless the affected facility has an annual capacity factor for coal, oil, and natural gas of 10 percent (0.10) or less and is subject to a federally enforceable requirement that limits operation of the affected facility to an annual capacity factor of 10 percent (0.10) or less: ER13JN07.025 Where: E <sup>n</sup> = NO <sup>X</sup> emission limit (expressed as NO <sup>2</sup> ), ng/J (lb/MMBtu); EL <sup>go</sup> = Appropriate emission limit from paragraph (a)(1) for combustion of natural gas or distillate oil, ng/J (lb/MMBtu); H <sup>go</sup> = Heat input from combustion of natural gas, distillate oil and gaseous byproduct/waste, J (MMBtu); EL <sup>ro</sup> = Appropriate emission limit from paragraph (a)(2) for combustion of residual oil and/or byproduct/waste, ng/J (lb/MMBtu); H <sup>ro</sup> = Heat input from combustion of residual oil, J (MMBtu); EL <sup>c</sup> = Appropriate emission limit from paragraph (a)(3) for combustion of coal, ng/J (lb/MMBtu); and H <sup>c</sup> = Heat input from combustion of coal, J (MMBtu).
(f)Any owner or operator of an affected facility that combusts byproduct/waste with either natural gas or oil may petition the Administrator within 180 days of the initial startup of the affected facility to establish a NO <sup>X</sup> emission limit that shall apply specifically to that affected facility when the byproduct/waste is combusted. The petition shall include sufficient and appropriate data, as determined by the Administrator, such as NO <sup>X</sup> emissions from the affected facility, waste composition (including nitrogen content), and combustion conditions to allow the Administrator to confirm that the affected facility is unable to comply with the emission limits in paragraph
(e)of this section and to determine the appropriate emission limit for the affected facility.
(1)Any owner or operator of an affected facility petitioning for a facility-specific NO <sup>X</sup> emission limit under this section shall:
(i)Demonstrate compliance with the emission limits for natural gas and distillate oil in paragraph (a)(1) of this section or for residual oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, by conducting a 30-day performance test as provided in § 60.46b(e). During the performance test only natural gas, distillate oil, or residual oil shall be combusted in the affected facility; and
(ii)Demonstrate that the affected facility is unable to comply with the emission limits for natural gas and distillate oil in paragraph (a)(1) of this section or for residual oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, when gaseous or liquid byproduct/waste is combusted in the affected facility under the same conditions and using the same technological system of emission reduction applied when demonstrating compliance under paragraph (f)(1)(i) of this section.
(2)The NO <sup>X</sup> emission limits for natural gas or distillate oil in paragraph (a)(1) of this section or for residual oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, shall be applicable to the affected facility until and unless the petition is approved by the Administrator. If the petition is approved by the Administrator, a facility-specific NO <sup>X</sup> emission limit will be established at the NO <sup>X</sup> emission level achievable when the affected facility is combusting oil or natural gas and byproduct/waste in a manner that the Administrator determines to be consistent with minimizing NO <sup>X</sup> emissions. In lieu of amending this subpart, a letter will be sent to the facility describing the facility-specific NO <sup>X</sup> limit. The facility shall use the compliance procedures detailed in the letter and make the letter available to the public. If the Administrator determines it is appropriate, the conditions and requirements of the letter can be reviewed and changed at any point.
(g)Any owner or operator of an affected facility that combusts hazardous waste (as defined by 40 CFR part 261 or 40 CFR part 761) with natural gas or oil may petition the Administrator within 180 days of the initial startup of the affected facility for a waiver from compliance with the NO <sup>X</sup> emission limit that applies specifically to that affected facility. The petition must include sufficient and appropriate data, as determined by the Administrator, on NO <sup>X</sup> emissions from the affected facility, waste destruction efficiencies, waste composition (including nitrogen content), the quantity of specific wastes to be combusted and combustion conditions to allow the Administrator to determine if the affected facility is able to comply with the NO <sup>X</sup> emission limits required by this section. The owner or operator of the affected facility shall demonstrate that when hazardous waste is combusted in the affected facility, thermal destruction efficiency requirements for hazardous waste specified in an applicable federally enforceable requirement preclude compliance with the NO <sup>X</sup> emission limits of this section. The NO <sup>X</sup> emission limits for natural gas or distillate oil in paragraph (a)(1) of this section or for residual oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, are applicable to the affected facility until and unless the petition is approved by the Administrator. (See 40 CFR 761.70 for regulations applicable to the incineration of materials containing polychlorinated biphenyls (PCB's).) In lieu of amending this subpart, a letter will be sent to the facility describing the facility-specific NO <sup>X</sup> limit. The facility shall use the compliance procedures detailed in the letter and make the letter available to the public. If the Administrator determines it is appropriate, the conditions and requirements of the letter can be reviewed and changed at any point.
(h)For purposes of paragraph
(i)of this section, the NO <sup>X</sup> standards under this section apply at all times including periods of startup, shutdown, or malfunction.
(i)Except as provided under paragraph
(j)of this section, compliance with the emission limits under this section is determined on a 30-day rolling average basis.
(j)Compliance with the emission limits under this section is determined on a 24-hour average basis for the initial performance test and on a 3-hour average basis for subsequent performance tests for any affected facilities that:
(1)Combust, alone or in combination, only natural gas, distillate oil, or residual oil with a nitrogen content of 0.30 weight percent or less;
(2)Have a combined annual capacity factor of 10 percent or less for natural gas, distillate oil, and residual oil with a nitrogen content of 0.30 weight percent or less; and
(3)Are subject to a federally enforceable requirement limiting operation of the affected facility to the firing of natural gas, distillate oil, and/or residual oil with a nitrogen content of 0.30 weight percent or less and limiting operation of the affected facility to a combined annual capacity factor of 10 percent or less for natural gas, distillate oil, and residual oil with a nitrogen content of 0.30 weight percent or less.
(k)Affected facilities that meet the criteria described in paragraphs (j)(1), (2), and
(3)of this section, and that have a heat input capacity of 73 MW (250 MMBtu/hr) or less, are not subject to the NO <sup>X</sup> emission limits under this section.
(l)On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction or reconstruction after July 9, 1997 shall cause to be discharged into the atmosphere from that affected facility any gases that contain NO <sup>X</sup> (expressed as NO <sup>2</sup> ) in excess of the following limits:
(1)If the affected facility combusts coal, oil, or natural gas, or a mixture of these fuels, or with any other fuels: A limit of 86 ng/J (0.20 lb/MMBtu) heat input unless the affected facility has an annual capacity factor for coal, oil, and natural gas of 10 percent (0.10) or less and is subject to a federally enforceable requirement that limits operation of the facility to an annual capacity factor of 10 percent (0.10) or less for coal, oil, and natural gas; or
(2)If the affected facility has a low heat release rate and combusts natural gas or distillate oil in excess of 30 percent of the heat input on a 30-day rolling average from the combustion of all fuels, a limit determined by use of the following formula: ER13JN07.026 Where: E <sup>n</sup> = NO <sup>X</sup> emission limit, (lb/MMBtu); H <sup>go</sup> = 30-day heat input from combustion of natural gas or distillate oil; and H <sup>r</sup> = 30-day heat input from combustion of any other fuel.
(3)After February 27, 2006, units where more than 10 percent of total annual output is electrical or mechanical may comply with an optional limit of 270 ng/J (2.1 lb/MWh) gross energy output, based on a 30-day rolling average. Units complying with this output-based limit must demonstrate compliance according to the procedures of § 60.48Da(i) of subpart Da of this part, and must monitor emissions according to § 60.49Da(c), (k), through
(n)of subpart Da of this part. § 60.45b Compliance and performance test methods and procedures for sulfur dioxide.
(a)The SO <sup>2</sup> emission standards under § 60.42b apply at all times. Facilities burning coke oven gas alone or in combination with any other gaseous fuels or distillate oil and complying with the fuel based limit under § 60.42b(d) or § 60.42b(k)(2) are allowed to exceed the limit 30 operating days per calendar year for by-product plant maintenance.
(b)In conducting the performance tests required under § 60.8, the owner or operator shall use the methods and procedures in appendix A (including fuel certification and sampling) of this part or the methods and procedures as specified in this section, except as provided in § 60.8(b). Section 60.8(f) does not apply to this section. The 30-day notice required in § 60.8(d) applies only to the initial performance test unless otherwise specified by the Administrator.
(c)The owner or operator of an affected facility shall conduct performance tests to determine compliance with the percent of potential SO <sup>2</sup> emission rate (% P <sup>s</sup> ) and the SO <sup>2</sup> emission rate (E <sup>s</sup> ) pursuant to § 60.42b following the procedures listed below, except as provided under paragraph
(d)and
(k)of this section.
(1)The initial performance test shall be conducted over 30 consecutive operating days of the steam generating unit. Compliance with the SO <sup>2</sup> standards shall be determined using a 30-day average. The first operating day included in the initial performance test shall be scheduled within 30 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of the facility.
(2)If only coal, only oil, or a mixture of coal and oil is combusted, the following procedures are used:
(i)The procedures in Method 19 of appendix A of this part are used to determine the hourly SO <sup>2</sup> emission rate (E <sup>ho</sup> ) and the 30-day average emission rate (E <sup>ao</sup> ). The hourly averages used to compute the 30-day averages are obtained from the continuous emission monitoring system
(CEMS)of § 60.47b
(a)or (b).
(ii)The percent of potential SO <sup>2</sup> emission rate (%P <sup>s</sup> ) emitted to the atmosphere is computed using the following formula: ER13JN07.027 Where: %P <sup>s</sup> = Potential SO <sup>2</sup> emission rate, percent; %R <sup>g</sup> = SO <sup>2</sup> removal efficiency of the control device as determined by Method 19 of appendix A of this part, in percent; and %R <sup>f</sup> = SO <sup>2</sup> removal efficiency of fuel pretreatment as determined by Method 19 of appendix A of this part, in percent.
(3)If coal or oil is combusted with other fuels, the same procedures required in paragraph (c)(2) of this section are used, except as provided in the following:
(i)An adjusted hourly SO <sup>2</sup> emission rate (E <sup>ho</sup> o ) is used in Equation 19-19 of Method 19 of appendix A of this part to compute an adjusted 30-day average emission rate (E <sup>ao</sup> o ). The Eho° is computed using the following formula: ER13JN07.028 Where: E <sup>ho</sup> o = Adjusted hourly SO <sup>2</sup> emission rate, ng/J (lb/MMBtu); E <sup>ho</sup> = Hourly SO <sup>2</sup> emission rate, ng/J (lb/MMBtu); E <sup>w</sup> = SO <sup>2</sup> concentration in fuels other than coal and oil combusted in the affected facility, as determined by the fuel sampling and analysis procedures in Method 19 of appendix A of this part, ng/J (lb/MMBtu). The value E <sup>w</sup> for each fuel lot is used for each hourly average during the time that the lot is being combusted; and X <sup>k</sup> = Fraction of total heat input from fuel combustion derived from coal, oil, or coal and oil, as determined by applicable procedures in Method 19 of appendix A of this part.
(ii)To compute the percent of potential SO <sup>2</sup> emission rate (%P <sup>s</sup> ), an adjusted %R <sup>g</sup> (%R <sup>g</sup> o ) is computed from the adjusted E <sup>ao</sup> o from paragraph (b)(3)(i) of this section and an adjusted average SO <sup>2</sup> inlet rate (E <sup>ai</sup> o ) using the following formula: ER13JN07.029 To compute E <sup>ai</sup> o , an adjusted hourly SO <sup>2</sup> inlet rate (E <sup>hi</sup> o ) is used. The E <sup>hi</sup> o is computed using the following formula: ER13JN07.030 Where: E <sup>hi</sup> o = Adjusted hourly SO <sup>2</sup> inlet rate, ng/J (lb/MMBtu); and E <sup>hi</sup> = Hourly SO <sup>2</sup> inlet rate, ng/J (lb/MMBtu).
(4)The owner or operator of an affected facility subject to paragraph (b)(3) of this section does not have to measure parameters E <sup>w</sup> or X <sup>k</sup> if the owner or operator elects to assume that X <sup>k</sup> = 1.0. Owners or operators of affected facilities who assume X <sup>k</sup> = 1.0 shall:
(i)Determine %P <sup>s</sup> following the procedures in paragraph (c)(2) of this section; and
(ii)Sulfur dioxide emissions (E <sup>s</sup> ) are considered to be in compliance with SO <sup>2</sup> emission limits under § 60.42b.
(5)The owner or operator of an affected facility that qualifies under the provisions of § 60.42b(d) does not have to measure parameters E <sup>w</sup> or X <sup>k</sup> under paragraph (b)(3) of this section if the owner or operator of the affected facility elects to measure SO <sup>2</sup> emission rates of the coal or oil following the fuel sampling and analysis procedures under Method 19 of appendix A of this part.
(d)Except as provided in paragraph
(j)of this section, the owner or operator of an affected facility that combusts only very low sulfur oil, has an annual capacity factor for oil of 10 percent (0.10) or less, and is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor for oil of 10 percent (0.10) or less shall:
(1)Conduct the initial performance test over 24 consecutive steam generating unit operating hours at full load;
(2)Determine compliance with the standards after the initial performance test based on the arithmetic average of the hourly emissions data during each steam generating unit operating day if a CEMS is used, or based on a daily average if Method 6B of appendix A of this part or fuel sampling and analysis procedures under Method 19 of appendix A of this part are used.
(e)The owner or operator of an affected facility subject to § 60.42b(d)(1) shall demonstrate the maximum design capacity of the steam generating unit by operating the facility at maximum capacity for 24 hours. This demonstration will be made during the initial performance test and a subsequent demonstration may be requested at any other time. If the 24-hour average firing rate for the affected facility is less than the maximum design capacity provided by the manufacturer of the affected facility, the 24-hour average firing rate shall be used to determine the capacity utilization rate for the affected facility, otherwise the maximum design capacity provided by the manufacturer is used.
(f)For the initial performance test required under § 60.8, compliance with the SO <sup>2</sup> emission limits and percent reduction requirements under § 60.42b is based on the average emission rates and the average percent reduction for SO <sup>2</sup> for the first 30 consecutive steam generating unit operating days, except as provided under paragraph
(d)of this section. The initial performance test is the only test for which at least 30 days prior notice is required unless otherwise specified by the Administrator. The initial performance test is to be scheduled so that the first steam generating unit operating day of the 30 successive steam generating unit operating days is completed within 30 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of the facility. The boiler load during the 30-day period does not have to be the maximum design load, but must be representative of future operating conditions and include at least one 24-hour period at full load.
(g)After the initial performance test required under § 60.8, compliance with the SO <sup>2</sup> emission limits and percent reduction requirements under § 60.42b is based on the average emission rates and the average percent reduction for SO <sup>2</sup> for 30 successive steam generating unit operating days, except as provided under paragraph (d). A separate performance test is completed at the end of each steam generating unit operating day after the initial performance test, and a new 30-day average emission rate and percent reduction for SO <sup>2</sup> are calculated to show compliance with the standard.
(h)Except as provided under paragraph
(i)of this section, the owner or operator of an affected facility shall use all valid SO <sup>2</sup> emissions data in calculating %P <sup>s</sup> and E <sup>ho</sup> under paragraph (c), of this section whether or not the minimum emissions data requirements under § 60.46b are achieved. All valid emissions data, including valid SO <sup>2</sup> emission data collected during periods of startup, shutdown and malfunction, shall be used in calculating %P <sup>s</sup> and E <sup>ho</sup> pursuant to paragraph
(c)of this section.
(i)During periods of malfunction or maintenance of the SO <sup>2</sup> control systems when oil is combusted as provided under § 60.42b(i), emission data are not used to calculate %P <sup>s</sup> or E <sup>s</sup> under § 60.42b(a),
(b)or (c), however, the emissions data are used to determine compliance with the emission limit under § 60.42b(i).
(j)The owner or operator of an affected facility that combusts very low sulfur oil is not subject to the compliance and performance testing requirements of this section if the owner or operator obtains fuel receipts as described in § 60.49b(r).
(k)The owner or operator of an affected facility seeking to demonstrate compliance under §§ 60.42b(d)(4), 60.42b(j), and 60.42b(k)(2) shall follow the applicable procedures under § 60.49b(r). § 60.46b Compliance and performance test methods and procedures for particulate matter and nitrogen oxides.
(a)The PM emission standards and opacity limits under § 60.43b apply at all times except during periods of startup, shutdown, or malfunction. The NO <sup>X</sup> emission standards under § 60.44b apply at all times.
(b)Compliance with the PM emission standards under § 60.43b shall be determined through performance testing as described in paragraph
(d)of this section, except as provided in paragraph
(i)of this section.
(c)Compliance with the NO <sup>X</sup> emission standards under § 60.44b shall be determined through performance testing under paragraph
(e)or (f), or under paragraphs
(g)and
(h)of this section, as applicable.
(d)To determine compliance with the PM emission limits and opacity limits under § 60.43b, the owner or operator of an affected facility shall conduct an initial performance test as required under § 60.8, and shall conduct subsequent performance tests as requested by the Administrator, using the following procedures and reference methods:
(1)Method 3B of appendix A of this part is used for gas analysis when applying Method 5 or 17 of appendix A of this part.
(2)Method 5, 5B, or 17 of appendix A of this part shall be used to measure the concentration of PM as follows:
(i)Method 5 of appendix A of this part shall be used at affected facilities without wet flue gas desulfurization
(FGD)systems; and
(ii)Method 17 of appendix A of this part may be used at facilities with or without wet scrubber systems provided the stack gas temperature does not exceed a temperature of 160 °C (32 °F). The procedures of sections 2.1 and 2.3 of Method 5B of appendix A of this part may be used in Method 17 of appendix A of this part only if it is used after a wet FGD system. Do not use Method 17 of appendix A of this part after wet FGD systems if the effluent is saturated or laden with water droplets.
(iii)Method 5B of appendix A of this part is to be used only after wet FGD systems.
(3)Method 1 of appendix A of this part is used to select the sampling site and the number of traverse sampling points. The sampling time for each run is at least 120 minutes and the minimum sampling volume is 1.7 dscm (60 dscf) except that smaller sampling times or volumes may be approved by the Administrator when necessitated by process variables or other factors.
(4)For Method 5 of appendix A of this part, the temperature of the sample gas in the probe and filter holder is monitored and is maintained at 160±14 °C (320±25 °F).
(5)For determination of PM emissions, the oxygen (O <sup>2</sup> ) or CO <sup>2</sup> sample is obtained simultaneously with each run of Method 5, 5B, or 17 of appendix A of this part by traversing the duct at the same sampling location.
(6)For each run using Method 5, 5B, or 17 of appendix A of this part, the emission rate expressed in ng/J heat input is determined using:
(i)The O <sup>2</sup> or CO <sup>2</sup> measurements and PM measurements obtained under this section;
(ii)The dry basis F factor; and
(iii)The dry basis emission rate calculation procedure contained in Method 19 of appendix A of this part.
(7)Method 9 of appendix A of this part is used for determining the opacity of stack emissions.
(e)To determine compliance with the emission limits for NO <sup>X</sup> required under § 60.44b, the owner or operator of an affected facility shall conduct the performance test as required under § 60.8 using the continuous system for monitoring NO <sup>X</sup> under § 60.48(b).
(1)For the initial compliance test, NO <sup>X</sup> from the steam generating unit are monitored for 30 successive steam generating unit operating days and the 30-day average emission rate is used to determine compliance with the NO <sup>X</sup> emission standards under § 60.44b. The 30-day average emission rate is calculated as the average of all hourly emissions data recorded by the monitoring system during the 30-day test period.
(2)Following the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, the owner or operator of an affected facility which combusts coal or which combusts residual oil having a nitrogen content greater than 0.30 weight percent shall determine compliance with the NO <sup>X</sup> emission standards under § 60.44b on a continuous basis through the use of a 30-day rolling average emission rate. A new 30-day rolling average emission rate is calculated each steam generating unit operating day as the average of all of the hourly NO <sup>X</sup> emission data for the preceding 30 steam generating unit operating days.
(3)Following the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, the owner or operator of an affected facility that has a heat input capacity greater than 73 MW (250 MMBtu/hr) and that combusts natural gas, distillate oil, or residual oil having a nitrogen content of 0.30 weight percent or less shall determine compliance with the NO <sup>X</sup> standards under § 60.44b on a continuous basis through the use of a 30-day rolling average emission rate. A new 30-day rolling average emission rate is calculated each steam generating unit operating day as the average of all of the hourly NO <sup>X</sup> emission data for the preceding 30 steam generating unit operating days.
(4)Following the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, the owner or operator of an affected facility that has a heat input capacity of 73 MW (250 MMBtu/hr) or less and that combusts natural gas, distillate oil, or residual oil having a nitrogen content of 0.30 weight percent or less shall upon request determine compliance with the NO <sup>X</sup> standards under § 60.44b through the use of a 30-day performance test. During periods when performance tests are not requested, NO <sup>X</sup> emissions data collected pursuant to § 60.48b(g)(1) or § 60.48b(g)(2) are used to calculate a 30-day rolling average emission rate on a daily basis and used to prepare excess emission reports, but will not be used to determine compliance with the NO <sup>X</sup> emission standards. A new 30-day rolling average emission rate is calculated each steam generating unit operating day as the average of all of the hourly NO <sup>X</sup> emission data for the preceding 30 steam generating unit operating days.
(5)If the owner or operator of an affected facility that combusts residual oil does not sample and analyze the residual oil for nitrogen content, as specified in § 60.49b(e), the requirements of § 60.48b(g)(1) apply and the provisions of § 60.48b(g)(2) are inapplicable.
(f)To determine compliance with the emissions limits for NO <sup>X</sup> required by § 60.44b(a)(4) or § 60.44b(l) for duct burners used in combined cycle systems, either of the procedures described in paragraph (f)(1) or
(2)of this section may be used:
(1)The owner or operator of an affected facility shall conduct the performance test required under § 60.8 as follows:
(i)The emissions rate
(E)of NO <sup>X</sup> shall be computed using Equation 1 in this section: ER13JN07.031 Where: E = Emissions rate of NO <sup>X</sup> from the duct burner, ng/J (lb/MMBtu) heat input; E <sup>sg</sup> = Combined effluent emissions rate, in ng/J (lb/MMBtu) heat input using appropriate F factor as described in Method 19 of appendix A of this part; H <sup>g</sup> = Heat input rate to the combustion turbine, in J/hr (MMBtu/hr); H <sup>b</sup> = Heat input rate to the duct burner, in J/hr (MMBtu/hr); and E <sup>g</sup> = Emissions rate from the combustion turbine, in ng/J (lb/MMBtu) heat input calculated using appropriate F factor as described in Method 19 of appendix A of this part.
(ii)Method 7E of appendix A of this part shall be used to determine the NO <sup>X</sup> concentrations. Method 3A or 3B of appendix A of this part shall be used to determine O <sup>2</sup> concentration.
(iii)The owner or operator shall identify and demonstrate to the Administrator's satisfaction suitable methods to determine the average hourly heat input rate to the combustion turbine and the average hourly heat input rate to the affected duct burner.
(iv)Compliance with the emissions limits under § 60.44b(a)(4) or § 60.44b(l) is determined by the three-run average (nominal 1-hour runs) for the initial and subsequent performance tests; or
(2)The owner or operator of an affected facility may elect to determine compliance on a 30-day rolling average basis by using the CEMS specified under § 60.48b for measuring NO <sup>X</sup> and O <sup>2</sup> and meet the requirements of § 60.48b. The sampling site shall be located at the outlet from the steam generating unit. The NO <sup>X</sup> emissions rate at the outlet from the steam generating unit shall constitute the NO <sup>X</sup> emissions rate from the duct burner of the combined cycle system.
(g)The owner or operator of an affected facility described in § 60.44b(j) or § 60.44b(k) shall demonstrate the maximum heat input capacity of the steam generating unit by operating the facility at maximum capacity for 24 hours. The owner or operator of an affected facility shall determine the maximum heat input capacity using the heat loss method described in sections 5 and 7.3 of the ASME *Power Test Codes* 4.1 (incorporated by reference, see § 60.17). This demonstration of maximum heat input capacity shall be made during the initial performance test for affected facilities that meet the criteria of § 60.44b(j). It shall be made within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial start-up of each facility, for affected facilities meeting the criteria of § 60.44b(k). Subsequent demonstrations may be required by the Administrator at any other time. If this demonstration indicates that the maximum heat input capacity of the affected facility is less than that stated by the manufacturer of the affected facility, the maximum heat input capacity determined during this demonstration shall be used to determine the capacity utilization rate for the affected facility. Otherwise, the maximum heat input capacity provided by the manufacturer is used.
(h)The owner or operator of an affected facility described in § 60.44b(j) that has a heat input capacity greater than 73 MW (250 MMBtu/hr) shall:
(1)Conduct an initial performance test as required under § 60.8 over a minimum of 24 consecutive steam generating unit operating hours at maximum heat input capacity to demonstrate compliance with the NO <sup>X</sup> emission standards under § 60.44b using Method 7, 7A, 7E of appendix A of this part, or other approved reference methods; and
(2)Conduct subsequent performance tests once per calendar year or every 400 hours of operation (whichever comes first) to demonstrate compliance with the NO <sup>X</sup> emission standards under § 60.44b over a minimum of 3 consecutive steam generating unit operating hours at maximum heat input capacity using Method 7, 7A, 7E of appendix A of this part, or other approved reference methods.
(i)The owner or operator of an affected facility seeking to demonstrate compliance under paragraph § 60.43b(h)(5) shall follow the applicable procedures under § 60.49b(r).
(j)In place of PM testing with EPA Reference Method 5, 5B, or 17 of appendix A of this part, an owner or operator may elect to install, calibrate, maintain, and operate a CEMS for monitoring PM emissions discharged to the atmosphere and record the output of the system. The owner or operator of an affected facility who elects to continuously monitor PM emissions instead of conducting performance testing using EPA Method 5, 5B, or 17 of appendix A of this part shall comply with the requirements specified in paragraphs (j)(1) through (j)(13) of this section.
(1)Notify the Administrator one month before starting use of the system.
(2)Notify the Administrator one month before stopping use of the system.
(3)The monitor shall be installed, evaluated, and operated in accordance with § 60.13 of subpart A of this part.
(4)The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the affected facility, as specified under § 60.8 of subpart A of this part or within 180 days of notification to the Administrator of use of the CEMS if the owner or operator was previously determining compliance by Method 5, 5B, or 17 of appendix A of this part performance tests, whichever is later.
(5)The owner or operator of an affected facility shall conduct an initial performance test for PM emissions as required under § 60.8 of subpart A of this part. Compliance with the PM emission limit shall be determined by using the CEMS specified in paragraph
(j)of this section to measure PM and calculating a 24-hour block arithmetic average emission concentration using EPA Reference Method 19 of appendix A of this part, section 4.1.
(6)Compliance with the PM emission limit shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average emission concentrations using CEMS outlet data.
(7)At a minimum, valid CEMS hourly averages shall be obtained as specified in paragraphs (j)(7)(i) of this section for 75 percent of the total operating hours per 30-day rolling average.
(i)At least two data points per hour shall be used to calculate each 1-hour arithmetic average.
(ii)[Reserved]
(8)The 1-hour arithmetic averages required under paragraph (j)(7) of this section shall be expressed in ng/J or lb/MMBtu heat input and shall be used to calculate the boiler operating day daily arithmetic average emission concentrations. The 1-hour arithmetic averages shall be calculated using the data points required under § 60.13(e)(2) of subpart A of this part.
(9)All valid CEMS data shall be used in calculating average emission concentrations even if the minimum CEMS data requirements of paragraph (j)(7) of this section are not met.
(10)The CEMS shall be operated according to Performance Specification 11 in appendix B of this part.
(11)During the correlation testing runs of the CEMS required by Performance Specification 11 in appendix B of this part, PM and O <sup>2</sup> (or CO <sup>2</sup> ) data shall be collected concurrently (or within a 30-to 60-minute period) by both the continuous emission monitors and the test methods specified in paragraphs (j)(7)(i) of this section.
(i)For PM, EPA Reference Method 5, 5B, or 17 of appendix A of this part shall be used.
(ii)For O <sup>2</sup> (or CO <sup>2</sup> ), EPA reference Method 3, 3A, or 3B of appendix A of this part, as applicable shall be used.
(12)Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 2 in appendix F of this part. Relative Response Audit's must be performed annually and Response Correlation Audits must be performed every 3 years.
(13)When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by the Administrator or EPA Reference Method 19 of appendix A of this part to provide, as necessary, valid emissions data for a minimum of 75 percent of total operating hours per 30-day rolling average. § 60.47b Emission monitoring for sulfur dioxide.
(a)Except as provided in paragraphs (b), (f), and
(h)of this section, the owner or operator of an affected facility subject to the SO <sup>2</sup> standards under § 60.42b shall install, calibrate, maintain, and operate CEMS for measuring SO <sup>2</sup> concentrations and either O <sup>2</sup> or CO <sup>2</sup> concentrations and shall record the output of the systems. For units complying with the percent reduction standard, the SO <sup>2</sup> and either O <sup>2</sup> or CO <sup>2</sup> concentrations shall both be monitored at the inlet and outlet of the SO <sup>2</sup> control device. If the owner or operator has installed and certified SO <sup>2</sup> and O <sup>2</sup> or CO <sup>2</sup> CEMS according to the requirements of § 75.20(c)(1) of this chapter and appendix A to part 75 of this chapter, and is continuing to meet the ongoing quality assurance requirements of § 75.21 of this chapter and appendix B to part 75 of this chapter, those CEMS may be used to meet the requirements of this section, provided that:
(1)When relative accuracy testing is conducted, SO <sup>2</sup> concentration data and CO <sup>2</sup> (or O <sup>2</sup> ) data are collected simultaneously; and
(2)In addition to meeting the applicable SO <sup>2</sup> and CO <sup>2</sup> (or O <sup>2</sup> ) relative accuracy specifications in Figure 2 of appendix B to part 75 of this chapter, the relative accuracy
(RA)standard in section 13.2 of Performance Specification 2 in appendix B to this part is met when the RA is calculated on a lb/MMBtu basis; and
(3)The reporting requirements of § 60.49b are met. SO <sup>2</sup> and CO <sup>2</sup> (or O <sup>2</sup> ) data used to meet the requirements of § 60.49b shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the SO <sup>2</sup> data have been bias adjusted according to the procedures of part 75 of this chapter.
(b)As an alternative to operating CEMS as required under paragraph
(a)of this section, an owner or operator may elect to determine the average SO <sup>2</sup> emissions and percent reduction by:
(1)Collecting coal or oil samples in an as-fired condition at the inlet to the steam generating unit and analyzing them for sulfur and heat content according to Method 19 of appendix A of this part. Method 19 of appendix A of this part provides procedures for converting these measurements into the format to be used in calculating the average SO <sup>2</sup> input rate, or
(2)Measuring SO <sup>2</sup> according to Method 6B of appendix A of this part at the inlet or outlet to the SO <sup>2</sup> control system. An initial stratification test is required to verify the adequacy of the Method 6B of appendix A of this part sampling location. The stratification test shall consist of three paired runs of a suitable SO <sup>2</sup> and CO <sup>2</sup> measurement train operated at the candidate location and a second similar train operated according to the procedures in section 3.2 and the applicable procedures in section 7 of Performance Specification 2. Method 6B of appendix A of this part, Method 6A of appendix A of this part, or a combination of Methods 6 and 3 or 3B of appendix A of this part or Methods 6C and 3A of appendix A of this part are suitable measurement techniques. If Method 6B of appendix A of this part is used for the second train, sampling time and timer operation may be adjusted for the stratification test as long as an adequate sample volume is collected; however, both sampling trains are to be operated similarly. For the location to be adequate for Method 6B of appendix A of this part 24-hour tests, the mean of the absolute difference between the three paired runs must be less than 10 percent.
(3)A daily SO <sup>2</sup> emission rate, E <sup>D</sup> , shall be determined using the procedure described in Method 6A of appendix A of this part, section 7.6.2 (Equation 6A-8) and stated in ng/J (lb/MMBtu) heat input.
(4)The mean 30-day emission rate is calculated using the daily measured values in ng/J (lb/MMBtu) for 30 successive steam generating unit operating days using equation 19-20 of Method 19 of appendix A of this part.
(c)The owner or operator of an affected facility shall obtain emission data for at least 75 percent of the operating hours in at least 22 out of 30 successive boiler operating days. If this minimum data requirement is not met with a single monitoring system, the owner or operator of the affected facility shall supplement the emission data with data collected with other monitoring systems as approved by the Administrator or the reference methods and procedures as described in paragraph
(b)of this section.
(d)The 1-hour average SO <sup>2</sup> emission rates measured by the CEMS required by paragraph
(a)of this section and required under § 60.13(h) is expressed in ng/J or lb/MMBtu heat input and is used to calculate the average emission rates under § 60.42(b). Each 1-hour average SO <sup>2</sup> emission rate must be based on 30 or more minutes of steam generating unit operation. The hourly averages shall be calculated according to § 60.13(h)(2). Hourly SO <sup>2</sup> emission rates are not calculated if the affected facility is operated less than 30 minutes in a given clock hour and are not counted toward determination of a steam generating unit operating day.
(e)The procedures under § 60.13 shall be followed for installation, evaluation, and operation of the CEMS.
(1)Except as provided for in paragraph (e)(4) of this section, all CEMS shall be operated in accordance with the applicable procedures under Performance Specifications 1, 2, and 3 of appendix B of this part.
(2)Except as provided for in paragraph (e)(4) of this section, quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with Procedure 1 of appendix F of this part.
(3)For affected facilities combusting coal or oil, alone or in combination with other fuels, the span value of the SO <sup>2</sup> CEMS at the inlet to the SO <sup>2</sup> control device is 125 percent of the maximum estimated hourly potential SO <sup>2</sup> emissions of the fuel combusted, and the span value of the CEMS at the outlet to the SO <sup>2</sup> control device is 50 percent of the maximum estimated hourly potential SO <sup>2</sup> emissions of the fuel combusted. Alternatively, SO <sup>2</sup> span values determined according to section 2.1.1 in appendix A to part 75 of this chapter may be used.
(4)As an alternative to meeting the requirements of requirements of paragraphs (e)(1) and (e)(2) of this section, the owner or operator may elect to implement the following alternative data accuracy assessment procedures:
(i)For all required CO <sup>2</sup> and O <sup>2</sup> monitors and for SO <sup>2</sup> and NO <sup>X</sup> monitors with span values less than 100 ppm, the daily calibration error test and calibration adjustment procedures described in sections 2.1.1 and 2.1.3 of appendix B to part 75 of this chapter may be followed instead of the CD assessment procedures in Procedure 1, section 4.1 of appendix F to this part. If this option is selected, the data validation and out-of-control provisions in sections 2.1.4 and 2.1.5 of appendix B to part 75 of this chapter shall be followed instead of the excessive CD and out-of-control criteria in Procedure 1, section 4.3 of appendix F to this part. For the purposes of data validation under this subpart, the excessive CD and out-of-control criteria in Procedure 1, section 4.3 of appendix F to this part shall apply to SO <sup>2</sup> and NO <sup>X</sup> span values less than 100 ppm;
(ii)For all required CO <sup>2</sup> and O <sup>2</sup> monitors and for SO <sup>2</sup> and NO <sup>X</sup> monitors with span values greater than 30 ppm, quarterly linearity checks may be performed in accordance with section 2.2.1 of appendix B to part 75 of this chapter, instead of performing the cylinder gas audits
(CGAs)described in Procedure 1, section 5.1.2 of appendix F to this part. If this option is selected: The frequency of the linearity checks shall be as specified in section 2.2.1 of appendix B to part 75 of this chapter; the applicable linearity specifications in section 3.2 of appendix A to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.2.3 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this part; and the grace period provisions in section 2.2.4 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the cylinder gas audits described in Procedure 1, section 5.1.2 of appendix F to this part shall be performed for SO <sup>2</sup> and NO <sup>X</sup> span values less than or equal to 30 ppm; and
(iii)For SO <sup>2</sup> , CO <sup>2</sup> , and O <sup>2</sup> monitoring systems and for NO <sup>X</sup> emission rate monitoring systems, RATAs may be performed in accordance with section 2.3 of appendix B to part 75 of this chapter instead of following the procedures described in Procedure 1, section 5.1.1 of appendix F to this part. If this option is selected: The frequency of each RATA shall be as specified in section 2.3.1 of appendix B to part 75 of this chapter; the applicable relative accuracy specifications shown in Figure 2 in appendix B to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.3.2 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this part; and the grace period provisions in section 2.3.3 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the relative accuracy specification in section 13.2 of Performance Specification 2 in appendix B to this part shall be met on a lb/MMBtu basis for SO <sup>2</sup> (regardless of the SO <sup>2</sup> emission level during the RATA), and for NO <sup>X</sup> when the average NO <sup>X</sup> emission rate measured by the reference method during the RATA is less than 0.100 lb/MMBtu.
(f)The owner or operator of an affected facility that combusts very low sulfur oil or is demonstrating compliance under § 60.45b(k) is not subject to the emission monitoring requirements under paragraph
(a)of this section if the owner or operator maintains fuel records as described in § 60.49b(r). § 60.48b Emission monitoring for particulate matter and nitrogen oxides.
(a)Except as provided in paragraph
(j)of this section, the owner or operator of an affected facility subject to the opacity standard under § 60.43b shall install, calibrate, maintain, and operate a CEMS for measuring the opacity of emissions discharged to the atmosphere and record the output of the system.
(b)Except as provided under paragraphs (g), (h), and
(i)of this section, the owner or operator of an affected facility subject to a NO <sup>X</sup> standard under § 60.44b shall comply with either paragraphs (b)(1) or (b)(2) of this section.
(1)Install, calibrate, maintain, and operate CEMS for measuring NO <sup>X</sup> and O <sup>2</sup> (or CO <sup>2</sup> ) emissions discharged to the atmosphere, and shall record the output of the system; or
(2)If the owner or operator has installed a NO <sup>X</sup> emission rate CEMS to meet the requirements of part 75 of this chapter and is continuing to meet the ongoing requirements of part 75 of this chapter, that CEMS may be used to meet the requirements of this section, except that the owner or operator shall also meet the requirements of § 60.49b. Data reported to meet the requirements of § 60.49b shall not include data substituted using the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter.
(c)The CEMS required under paragraph
(b)of this section shall be operated and data recorded during all periods of operation of the affected facility except for CEMS breakdowns and repairs. Data is recorded during calibration checks, and zero and span adjustments.
(d)The 1-hour average NO <sup>X</sup> emission rates measured by the continuous NO <sup>X</sup> monitor required by paragraph
(b)of this section and required under § 60.13(h) shall be expressed in ng/J or lb/MMBtu heat input and shall be used to calculate the average emission rates under § 60.44b. The 1-hour averages shall be calculated using the data points required under § 60.13(h)(2).
(e)The procedures under § 60.13 shall be followed for installation, evaluation, and operation of the continuous monitoring systems.
(1)For affected facilities combusting coal, wood or municipal-type solid waste, the span value for a continuous monitoring system for measuring opacity shall be between 60 and 80 percent.
(2)For affected facilities combusting coal, oil, or natural gas, the span value for NO <sup>X</sup> is determined using one of the following procedures:
(i)Except as provided under paragraph (e)(2)(ii) of this section, NO <sup>X</sup> span values shall be determined as follows: Fuel Span values for NO <sup>X</sup>
(ppm)Natural gas 500. Oil 500. Coal 1,000. Mixtures 500 (x + y) + 1,000z. Where: x = Fraction of total heat input derived from natural gas; y = Fraction of total heat input derived from oil; and z = Fraction of total heat input derived from coal.
(ii)As an alternative to meeting the requirements of paragraph (e)(2)(i) of this section, the owner or operator of an affected facility may elect to use the NO <sup>X</sup> span values determined according to section 2.1.2 in appendix A to part 75 of this chapter.
(3)All span values computed under paragraph (e)(2)(i) of this section for combusting mixtures of regulated fuels are rounded to the nearest 500 ppm. Span values computed under paragraph (e)(2)(ii) of this section shall be rounded off according to section 2.1.2 in appendix A to part 75 of this chapter.
(f)When NO <sup>X</sup> emission data are not obtained because of CEMS breakdowns, repairs, calibration checks and zero and span adjustments, emission data will be obtained by using standby monitoring systems, Method 7 of appendix A of this part, Method 7A of appendix A of this part, or other approved reference methods to provide emission data for a minimum of 75 percent of the operating hours in each steam generating unit operating day, in at least 22 out of 30 successive steam generating unit operating days.
(g)The owner or operator of an affected facility that has a heat input capacity of 73 MW (250 MMBtu/hr) or less, and that has an annual capacity factor for residual oil having a nitrogen content of 0.30 weight percent or less, natural gas, distillate oil, or any mixture of these fuels, greater than 10 percent (0.10) shall:
(1)Comply with the provisions of paragraphs (b), (c), (d), (e)(2), (e)(3), and
(f)of this section; or
(2)Monitor steam generating unit operating conditions and predict NO <sup>X</sup> emission rates as specified in a plan submitted pursuant to § 60.49b(c).
(h)The owner or operator of a duct burner, as described in § 60.41b, that is subject to the NO <sup>X</sup> standards of § 60.44b(a)(4) or § 60.44b(l) is not required to install or operate a continuous emissions monitoring system to measure NO <sup>X</sup> emissions.
(i)The owner or operator of an affected facility described in § 60.44b(j) or § 60.44b(k) is not required to install or operate a CEMS for measuring NO <sup>X</sup> emissions.
(j)The owner or operator of an affected facility that meets the conditions in either paragraph (j)(1), (2), (3), (4), or
(5)of this section is not required to install or operate a COMS for measuring opacity if:
(1)The affected facility uses a PM CEMS to monitor PM emissions; or
(2)The affected facility burns only liquid (excluding residual oil) or gaseous fuels with potential SO <sup>2</sup> emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and does not use a post-combustion technology to reduce SO <sup>2</sup> or PM emissions. The owner or operator must maintain fuel records of the sulfur content of the fuels burned, as described under § 60.49b(r); or
(3)The affected facility burns coke oven gas alone or in combination with fuels meeting the criteria in paragraph (j)(2) of this section and does not use a post-combustion technology to reduce SO <sup>2</sup> or PM emissions; or
(4)The affected facility does not use post-combustion technology (except a wet scrubber) for reducing PM, SO <sup>2</sup> , or carbon monoxide
(CO)emissions, burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 weight percent sulfur, and is operated such that emissions of CO to the atmosphere from the affected facility are maintained at levels less than or equal to 0.15 lb/MMBtu on a steam generating unit operating day average basis. Owners and operators of affected facilities electing to comply with this paragraph must demonstrate compliance according to the procedures specified in paragraphs (j)(4)(i) through
(iv)of this section.
(i)You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs (j)(4)(i)(A) through
(D)of this section.
(A)The CO CEMS must be installed, certified, maintained, and operated according to the provisions in § 60.58b(i)(3) of subpart Eb of this part.
(B)Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis).
(C)At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-day rolling average basis. At least two data points per hour must be used to calculate each 1-hour average.
(D)Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be performed in accordance with procedure 1 in appendix F of this part.
(ii)You must calculate the 1-hour average CO emissions levels for each steam generating unit operating day by multiplying the average hourly CO output concentration measured by the CO CEMS times the corresponding average hourly flue gas flow rate and divided by the corresponding average hourly heat input to the affected source. The 24-hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission levels computed for each steam generating unit operating day.
(iii)You must evaluate the preceding 24-hour average CO emission level each steam generating unit operating day excluding periods of affected source startup, shutdown, or malfunction. If the 24-hour average CO emission level is greater than 0.15 lb/MMBtu, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of the high emission incident and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 0.15 lb/MMBtu or less.
(iv)You must record the CO measurements and calculations performed according to paragraph (j)(4) of this section and any corrective actions taken. The record of corrective action taken must include the date and time during which the 24-hour average CO emission level was greater than 0.15 lb/MMBtu, and the date, time, and description of the corrective action.
(5)The affected facility burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 weight percent sulfur and operates according to a written site-specific monitoring plan approved by the appropriate delegated permitting authority. This monitoring plan must include procedures and criteria for establishing and monitoring specific parameters for the affected facility indicative of compliance with the opacity standard.
(k)Owners or operators complying with the PM emission limit by using a PM CEMS monitor instead of monitoring opacity must calibrate, maintain, and operate a CEMS, and record the output of the system, for PM emissions discharged to the atmosphere as specified in § 60.46b(j). The CEMS specified in paragraph § 60.46b(j) shall be operated and data recorded during all periods of operation of the affected facility except for CEMS breakdowns and repairs. Data is recorded during calibration checks, and zero and span adjustments. § 60.49b Reporting and recordkeeping requirements.
(a)The owner or operator of each affected facility shall submit notification of the date of initial startup, as provided by § 60.7. This notification shall include:
(1)The design heat input capacity of the affected facility and identification of the fuels to be combusted in the affected facility;
(2)If applicable, a copy of any federally enforceable requirement that limits the annual capacity factor for any fuel or mixture of fuels under §§ 60.42b(d)(1), 60.43b(a)(2), (a)(3)(iii), (c)(2)(ii), (d)(2)(iii), 60.44b(c), (d), (e), (i), (j), (k), 60.45b(d), (g), 60.46b(h), or 60.48b(i);
(3)The annual capacity factor at which the owner or operator anticipates operating the facility based on all fuels fired and based on each individual fuel fired; and
(4)Notification that an emerging technology will be used for controlling emissions of SO <sup>2</sup> . The Administrator will examine the description of the emerging technology and will determine whether the technology qualifies as an emerging technology. In making this determination, the Administrator may require the owner or operator of the affected facility to submit additional information concerning the control device. The affected facility is subject to the provisions of § 60.42b(a) unless and until this determination is made by the Administrator.
(b)The owner or operator of each affected facility subject to the SO <sup>2</sup> , PM, and/or NO <sup>X</sup> emission limits under §§ 60.42b, 60.43b, and 60.44b shall submit to the Administrator the performance test data from the initial performance test and the performance evaluation of the CEMS using the applicable performance specifications in appendix B of this part. The owner or operator of each affected facility described in § 60.44b(j) or § 60.44b(k) shall submit to the Administrator the maximum heat input capacity data from the demonstration of the maximum heat input capacity of the affected facility.
(c)The owner or operator of each affected facility subject to the NO <sup>X</sup> standard of § 60.44b who seeks to demonstrate compliance with those standards through the monitoring of steam generating unit operating conditions under the provisions of § 60.48b(g)(2) shall submit to the Administrator for approval a plan that identifies the operating conditions to be monitored under § 60.48b(g)(2) and the records to be maintained under § 60.49b(j). This plan shall be submitted to the Administrator for approval within 360 days of the initial startup of the affected facility. If the plan is approved, the owner or operator shall maintain records of predicted nitrogen oxide emission rates and the monitored operating conditions, including steam generating unit load, identified in the plan. The plan shall:
(1)Identify the specific operating conditions to be monitored and the relationship between these operating conditions and NO <sup>X</sup> emission rates ( *i.e.* , ng/J or lbs/MMBtu heat input). Steam generating unit operating conditions include, but are not limited to, the degree of staged combustion ( *i.e.* , the ratio of primary air to secondary and/or tertiary air) and the level of excess air ( *i.e.* , flue gas O <sup>2</sup> level);
(2)Include the data and information that the owner or operator used to identify the relationship between NO <sup>X</sup> emission rates and these operating conditions; and
(3)Identify how these operating conditions, including steam generating unit load, will be monitored under § 60.48b(g) on an hourly basis by the owner or operator during the period of operation of the affected facility; the quality assurance procedures or practices that will be employed to ensure that the data generated by monitoring these operating conditions will be representative and accurate; and the type and format of the records of these operating conditions, including steam generating unit load, that will be maintained by the owner or operator under § 60.49b(j).
(d)The owner or operator of an affected facility shall record and maintain records of the amounts of each fuel combusted during each day and calculate the annual capacity factor individually for coal, distillate oil, residual oil, natural gas, wood, and municipal-type solid waste for the reporting period. The annual capacity factor is determined on a 12-month rolling average basis with a new annual capacity factor calculated at the end of each calendar month.
(e)For an affected facility that combusts residual oil and meets the criteria under §§ 60.46b(e)(4), 60.44b(j), or (k), the owner or operator shall maintain records of the nitrogen content of the residual oil combusted in the affected facility and calculate the average fuel nitrogen content for the reporting period. The nitrogen content shall be determined using ASTM Method D4629 (incorporated by reference, see § 60.17), or fuel suppliers. If residual oil blends are being combusted, fuel nitrogen specifications may be prorated based on the ratio of residual oils of different nitrogen content in the fuel blend.
(f)For facilities subject to the opacity standard under § 60.43b, the owner or operator shall maintain records of opacity.
(g)Except as provided under paragraph
(p)of this section, the owner or operator of an affected facility subject to the NO <sup>X</sup> standards under § 60.44b shall maintain records of the following information for each steam generating unit operating day:
(1)Calendar date;
(2)The average hourly NO <sup>X</sup> emission rates (expressed as NO <sup>2</sup> ) (ng/J or lb/MMBtu heat input) measured or predicted;
(3)The 30-day average NO <sup>X</sup> emission rates (ng/J or lb/MMBtu heat input) calculated at the end of each steam generating unit operating day from the measured or predicted hourly nitrogen oxide emission rates for the preceding 30 steam generating unit operating days;
(4)Identification of the steam generating unit operating days when the calculated 30-day average NO <sup>X</sup> emission rates are in excess of the NO <sup>X</sup> emissions standards under § 60.44b, with the reasons for such excess emissions as well as a description of corrective actions taken;
(5)Identification of the steam generating unit operating days for which pollutant data have not been obtained, including reasons for not obtaining sufficient data and a description of corrective actions taken;
(6)Identification of the times when emission data have been excluded from the calculation of average emission rates and the reasons for excluding data;
(7)Identification of “F” factor used for calculations, method of determination, and type of fuel combusted;
(8)Identification of the times when the pollutant concentration exceeded full span of the CEMS;
(9)Description of any modifications to the CEMS that could affect the ability of the CEMS to comply with Performance Specification 2 or 3; and
(10)Results of daily CEMS drift tests and quarterly accuracy assessments as required under appendix F, Procedure 1 of this part.
(h)The owner or operator of any affected facility in any category listed in paragraphs (h)(1) or
(2)of this section is required to submit excess emission reports for any excess emissions that occurred during the reporting period.
(1)Any affected facility subject to the opacity standards under § 60.43b(e) or to the operating parameter monitoring requirements under § 60.13(i)(1).
(2)Any affected facility that is subject to the NO <sup>X</sup> standard of § 60.44b, and that:
(i)Combusts natural gas, distillate oil, or residual oil with a nitrogen content of 0.3 weight percent or less; or
(ii)Has a heat input capacity of 73 MW (250 MMBtu/hr) or less and is required to monitor NO <sup>X</sup> emissions on a continuous basis under § 60.48b(g)(1) or steam generating unit operating conditions under § 60.48b(g)(2).
(3)For the purpose of § 60.43b, excess emissions are defined as all 6-minute periods during which the average opacity exceeds the opacity standards under § 60.43b(f).
(4)For purposes of § 60.48b(g)(1), excess emissions are defined as any calculated 30-day rolling average NO <sup>X</sup> emission rate, as determined under § 60.46b(e), that exceeds the applicable emission limits in § 60.44b.
(i)The owner or operator of any affected facility subject to the continuous monitoring requirements for NO <sup>X</sup> under § 60.48(b) shall submit reports containing the information recorded under paragraph
(g)of this section.
(j)The owner or operator of any affected facility subject to the SO <sup>2</sup> standards under § 60.42b shall submit reports.
(k)For each affected facility subject to the compliance and performance testing requirements of § 60.45b and the reporting requirement in paragraph
(j)of this section, the following information shall be reported to the Administrator:
(1)Calendar dates covered in the reporting period;
(2)Each 30-day average SO <sup>2</sup> emission rate (ng/J or lb/MMBtu heat input) measured during the reporting period, ending with the last 30-day period; reasons for noncompliance with the emission standards; and a description of corrective actions taken;
(3)Each 30-day average percent reduction in SO <sup>2</sup> emissions calculated during the reporting period, ending with the last 30-day period; reasons for noncompliance with the emission standards; and a description of corrective actions taken;
(4)Identification of the steam generating unit operating days that coal or oil was combusted and for which SO <sup>2</sup> or diluent (O <sup>2</sup> or CO <sup>2</sup> ) data have not been obtained by an approved method for at least 75 percent of the operating hours in the steam generating unit operating day; justification for not obtaining sufficient data; and description of corrective action taken;
(5)Identification of the times when emissions data have been excluded from the calculation of average emission rates; justification for excluding data; and description of corrective action taken if data have been excluded for periods other than those during which coal or oil were not combusted in the steam generating unit;
(6)Identification of “F” factor used for calculations, method of determination, and type of fuel combusted;
(7)Identification of times when hourly averages have been obtained based on manual sampling methods;
(8)Identification of the times when the pollutant concentration exceeded full span of the CEMS;
(9)Description of any modifications to the CEMS that could affect the ability of the CEMS to comply with Performance Specification 2 or 3;
(10)Results of daily CEMS drift tests and quarterly accuracy assessments as required under appendix F, Procedure 1 of this part; and
(11)The annual capacity factor of each fired as provided under paragraph
(d)of this section.
(l)For each affected facility subject to the compliance and performance testing requirements of § 60.45b(d) and the reporting requirements of paragraph
(j)of this section, the following information shall be reported to the Administrator:
(1)Calendar dates when the facility was in operation during the reporting period;
(2)The 24-hour average SO <sup>2</sup> emission rate measured for each steam generating unit operating day during the reporting period that coal or oil was combusted, ending in the last 24-hour period in the quarter; reasons for noncompliance with the emission standards; and a description of corrective actions taken;
(3)Identification of the steam generating unit operating days that coal or oil was combusted for which S0 <sup>2</sup> or diluent (O <sup>2</sup> or CO <sup>2</sup> ) data have not been obtained by an approved method for at least 75 percent of the operating hours; justification for not obtaining sufficient data; and description of corrective action taken;
(4)Identification of the times when emissions data have been excluded from the calculation of average emission rates; justification for excluding data; and description of corrective action taken if data have been excluded for periods other than those during which coal or oil were not combusted in the steam generating unit;
(5)Identification of “F” factor used for calculations, method of determination, and type of fuel combusted;
(6)Identification of times when hourly averages have been obtained based on manual sampling methods;
(7)Identification of the times when the pollutant concentration exceeded full span of the CEMS;
(8)Description of any modifications to the CEMS that could affect the ability of the CEMS to comply with Performance Specification 2 or 3; and
(9)Results of daily CEMS drift tests and quarterly accuracy assessments as required under Procedure 1 of appendix F 1 of this part. If the owner or operator elects to implement the alternative data assessment procedures described in §§ 60.47b(e)(4)(i) through (e)(4)(iii), each data assessment report shall include a summary of the results of all of the RATAs, linearity checks, CGAs, and calibration error or drift assessments required by §§ 60.47b(e)(4)(i) through (e)(4)(iii).
(m)For each affected facility subject to the SO <sup>2</sup> standards under § 60.42(b) for which the minimum amount of data required under § 60.47b(f) were not obtained during the reporting period, the following information is reported to the Administrator in addition to that required under paragraph
(k)of this section:
(1)The number of hourly averages available for outlet emission rates and inlet emission rates;
(2)The standard deviation of hourly averages for outlet emission rates and inlet emission rates, as determined in Method 19 of appendix A of this part, section 7;
(3)The lower confidence limit for the mean outlet emission rate and the upper confidence limit for the mean inlet emission rate, as calculated in Method 19 of appendix A of this part, section 7; and
(4)The ratio of the lower confidence limit for the mean outlet emission rate and the allowable emission rate, as determined in Method 19 of appendix A of this part, section 7.
(n)If a percent removal efficiency by fuel pretreatment ( *i.e.* , %R <sup>f</sup> ) is used to determine the overall percent reduction ( *i.e.* , %R <sup>o</sup> ) under § 60.45b, the owner or operator of the affected facility shall submit a signed statement with the report.
(1)Indicating what removal efficiency by fuel pretreatment ( *i.e.* , %R <sup>f</sup> ) was credited during the reporting period;
(2)Listing the quantity, heat content, and date each pre-treated fuel shipment was received during the reporting period, the name and location of the fuel pretreatment facility; and the total quantity and total heat content of all fuels received at the affected facility during the reporting period;
(3)Documenting the transport of the fuel from the fuel pretreatment facility to the steam generating unit; and
(4)Including a signed statement from the owner or operator of the fuel pretreatment facility certifying that the percent removal efficiency achieved by fuel pretreatment was determined in accordance with the provisions of Method 19 of appendix A of this part and listing the heat content and sulfur content of each fuel before and after fuel pretreatment.
(o)All records required under this section shall be maintained by the owner or operator of the affected facility for a period of 2 years following the date of such record.
(p)The owner or operator of an affected facility described in § 60.44b(j) or
(k)shall maintain records of the following information for each steam generating unit operating day:
(1)Calendar date;
(2)The number of hours of operation; and
(3)A record of the hourly steam load.
(q)The owner or operator of an affected facility described in § 60.44b(j) or § 60.44b(k) shall submit to the Administrator a report containing:
(1)The annual capacity factor over the previous 12 months;
(2)The average fuel nitrogen content during the reporting period, if residual oil was fired; and
(3)If the affected facility meets the criteria described in § 60.44b(j), the results of any NO <sup>X</sup> emission tests required during the reporting period, the hours of operation during the reporting period, and the hours of operation since the last NO <sup>X</sup> emission test.
(r)The owner or operator of an affected facility who elects to use the fuel based compliance alternatives in § 60.42b or § 60.43b shall either:
(1)The owner or operator of an affected facility who elects to demonstrate that the affected facility combusts only very low sulfur oil under § 60.42b(j)(2) or § 60.42b(k)(2) shall obtain and maintain at the affected facility fuel receipts from the fuel supplier that certify that the oil meets the definition of distillate oil as defined in § 60.41b and the applicable sulfur limit. For the purposes of this section, the distillate oil need not meet the fuel nitrogen content specification in the definition of distillate oil. Reports shall be submitted to the Administrator certifying that only very low sulfur oil meeting this definition and/or pipeline quality natural gas was combusted in the affected facility during the reporting period; or
(2)The owner or operator of an affected facility who elects to demonstrate compliance based on fuel analysis in § 60.42b or § 60.43b shall develop and submit a site-specific fuel analysis plan to the Administrator for review and approval no later than 60 days before the date you intend to demonstrate compliance. Each fuel analysis plan shall include a minimum initial requirement of weekly testing and each analysis report shall contain, at a minimum, the following information:
(i)The potential sulfur emissions rate of the representative fuel mixture in ng/J heat input;
(ii)The method used to determine the potential sulfur emissions rate of each constituent of the mixture. For distillate oil and natural gas a fuel receipt or tariff sheet is acceptable;
(iii)The ratio of different fuels in the mixture; and
(iv)The owner or operator can petition the Administrator to approve monthly or quarterly sampling in place of weekly sampling.
(s)Facility specific NO <sup>X</sup> standard for Cytec Industries Fortier Plant's C.AOG incinerator located in Westwego, Louisiana:
(1)*Definitions* . *Oxidation zone* is defined as the portion of the C.AOG incinerator that extends from the inlet of the oxidizing zone combustion air to the outlet gas stack. *Reducing zone* is defined as the portion of the C.AOG incinerator that extends from the burner section to the inlet of the oxidizing zone combustion air. *Total inlet air* is defined as the total amount of air introduced into the C.AOG incinerator for combustion of natural gas and chemical by-product waste and is equal to the sum of the air flow into the reducing zone and the air flow into the oxidation zone.
(2)*Standard for nitrogen oxides* .
(i)When fossil fuel alone is combusted, the NO <sup>X</sup> emission limit for fossil fuel in § 60.44b(a) applies.
(ii)When natural gas and chemical by-product waste are simultaneously combusted, the NO <sup>X</sup> emission limit is 289 ng/J (0.67 lb/MMBtu) and a maximum of 81 percent of the total inlet air provided for combustion shall be provided to the reducing zone of the C.AOG incinerator.
(3)*Emission monitoring* .
(i)The percent of total inlet air provided to the reducing zone shall be determined at least every 15 minutes by measuring the air flow of all the air entering the reducing zone and the air flow of all the air entering the oxidation zone, and compliance with the percentage of total inlet air that is provided to the reducing zone shall be determined on a 3-hour average basis.
(ii)The NO <sup>X</sup> emission limit shall be determined by the compliance and performance test methods and procedures for NO <sup>X</sup> in § 60.46b(i).
(iii)The monitoring of the NO <sup>X</sup> emission limit shall be performed in accordance with § 60.48b.
(4)*Reporting and recordkeeping requirements* .
(i)The owner or operator of the C.AOG incinerator shall submit a report on any excursions from the limits required by paragraph (a)(2) of this section to the Administrator with the quarterly report required by paragraph
(i)of this section.
(ii)The owner or operator of the C.AOG incinerator shall keep records of the monitoring required by paragraph (a)(3) of this section for a period of 2 years following the date of such record.
(iii)The owner of operator of the C.AOG incinerator shall perform all the applicable reporting and recordkeeping requirements of this section.
(t)Facility-specific NO <sup>X</sup> standard for Rohm and Haas Kentucky Incorporated's Boiler No. 100 located in Louisville, Kentucky:
(1)*Definitions* . *Air ratio control damper* is defined as the part of the low NO <sup>X</sup> burner that is adjusted to control the split of total combustion air delivered to the reducing and oxidation portions of the combustion flame. *Flue gas recirculation line* is defined as the part of Boiler No. 100 that recirculates a portion of the boiler flue gas back into the combustion air.
(2)*Standard for nitrogen oxides* .
(i)When fossil fuel alone is combusted, the NO <sup>X</sup> emission limit for fossil fuel in § 60.44b(a) applies.
(ii)When fossil fuel and chemical by-product waste are simultaneously combusted, the NO <sup>X</sup> emission limit is 473 ng/J (1.1 lb/MMBtu), and the air ratio control damper tee handle shall be at a minimum of 5 inches (12.7 centimeters) out of the boiler, and the flue gas recirculation line shall be operated at a minimum of 10 percent open as indicated by its valve opening position indicator.
(3)*Emission monitoring for nitrogen oxides* .
(i)The air ratio control damper tee handle setting and the flue gas recirculation line valve opening position indicator setting shall be recorded during each 8-hour operating shift.
(ii)The NO <sup>X</sup> emission limit shall be determined by the compliance and performance test methods and procedures for NO <sup>X</sup> in § 60.46b.
(iii)The monitoring of the NO <sup>X</sup> emission limit shall be performed in accordance with § 60.48b.
(4)*Reporting and recordkeeping requirements* .
(i)The owner or operator of Boiler No. 100 shall submit a report on any excursions from the limits required by paragraph (b)(2) of this section to the Administrator with the quarterly report required by § 60.49b(i).
(ii)The owner or operator of Boiler No. 100 shall keep records of the monitoring required by paragraph (b)(3) of this section for a period of 2 years following the date of such record.
(iii)The owner of operator of Boiler No. 100 shall perform all the applicable reporting and recordkeeping requirements of § 60.49b.
(u)*Site-specific standard for Merck & Co., Inc.'s Stonewall Plant in Elkton, Virginia* .
(1)This paragraph
(u)applies only to the pharmaceutical manufacturing facility, commonly referred to as the Stonewall Plant, located at Route 340 South, in Elkton, Virginia (“site”) and only to the natural gas-fired boilers installed as part of the powerhouse conversion required pursuant to 40 CFR 52.2454(g). The requirements of this paragraph shall apply, and the requirements of §§ 60.40b through 60.49b(t) shall not apply, to the natural gas-fired boilers installed pursuant to 40 CFR 52.2454(g).
(i)The site shall equip the natural gas-fired boilers with low NO <sup>X</sup> technology.
(ii)The site shall install, calibrate, maintain, and operate a continuous monitoring and recording system for measuring NO <sup>X</sup> emissions discharged to the atmosphere and opacity using a continuous emissions monitoring system or a predictive emissions monitoring system.
(iii)Within 180 days of the completion of the powerhouse conversion, as required by 40 CFR 52.2454, the site shall perform a performance test to quantify criteria pollutant emissions.
(2)[Reserved]
(v)The owner or operator of an affected facility may submit electronic quarterly reports for SO <sup>2</sup> and/or NO <sup>X</sup> and/or opacity in lieu of submitting the written reports required under paragraphs (h), (i), (j),
(k)or
(l)of this section. The format of each quarterly electronic report shall be coordinated with the permitting authority. The electronic report(s) shall be submitted no later than 30 days after the end of the calendar quarter and shall be accompanied by a certification statement from the owner or operator, indicating whether compliance with the applicable emission standards and minimum data requirements of this subpart was achieved during the reporting period. Before submitting reports in the electronic format, the owner or operator shall coordinate with the permitting authority to obtain their agreement to submit reports in this alternative format.
(w)The reporting period for the reports required under this subpart is each 6 month period. All reports shall be submitted to the Administrator and shall be postmarked by the 30th day following the end of the reporting period.
(x)Facility-specific NO <sup>X</sup> standard for Weyerhaeuser Company's No. 2 Power Boiler located in New Bern, North Carolina:
(1)*Standard for nitrogen oxides* .
(i)When fossil fuel alone is combusted, the NO <sup>X</sup> emission limit for fossil fuel in § 60.44b(a) applies.
(ii)When fossil fuel and chemical by-product waste are simultaneously combusted, the NO <sup>X</sup> emission limit is 215 ng/J (0.5 lb/MMBtu).
(2)*Emission monitoring for nitrogen oxides* .
(i)The NO <sup>X</sup> emissions shall be determined by the compliance and performance test methods and procedures for NO <sup>X</sup> in § 60.46b.
(ii)The monitoring of the NO <sup>X</sup> emissions shall be performed in accordance with § 60.48b.
(3)*Reporting and recordkeeping requirements* .
(i)The owner or operator of the No. 2 Power Boiler shall submit a report on any excursions from the limits required by paragraph (x)(2) of this section to the Administrator with the quarterly report required by § 60.49b(i).
(ii)The owner or operator of the No. 2 Power Boiler shall keep records of the monitoring required by paragraph (x)(3) of this section for a period of 2 years following the date of such record.
(iii)The owner or operator of the No. 2 Power Boiler shall perform all the applicable reporting and recordkeeping requirements of § 60.49b.
(y)Facility-specific NO <sup>X</sup> standard for INEOS USA's AOGI located in Lima, Ohio:
(1)*Standard for NO* <sup>X</sup> .
(i)When fossil fuel alone is combusted, the NO <sup>X</sup> emission limit for fossil fuel in § 60.44b(a) applies.
(ii)When fossil fuel and chemical byproduct/waste are simultaneously combusted, the NO <sup>X</sup> emission limit is 645 ng/J (1.5 lb/MMBtu).
(2)*Emission monitoring for NO* <sup>X</sup> .
(i)The NO <sup>X</sup> emissions shall be determined by the compliance and performance test methods and procedures for NO <sup>X</sup> in § 60.46b.
(ii)The monitoring of the NO <sup>X</sup> emissions shall be performed in accordance with § 60.48b.
(3)*Reporting and recordkeeping requirements* .
(i)The owner or operator of the AOGI shall submit a report on any excursions from the limits required by paragraph (y)(2) of this section to the Administrator with the quarterly report required by paragraph
(i)of this section.
(ii)The owner or operator of the AOGI shall keep records of the monitoring required by paragraph (y)(3) of this section for a period of 2 years following the date of such record.
(iii)The owner or operator of the AOGI shall perform all the applicable reporting and recordkeeping requirements of this section. Subpart Dc—[Amended] 6. Subpart Dc is revised to read as follows: Subpart Dc—Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units Sec. 60.40c Applicability and delegation of authority. 60.41c Definitions. 60.42c Standard for sulfur dioxide (SO <sup>2</sup> ). 60.43c Standard for particulate matter (PM). 60.44c Compliance and performance test methods and procedures for sulfur dioxide. 60.45c Compliance and performance test methods and procedures for particulate matter. 60.46c Emission monitoring for sulfur dioxide. 60.47c Emission monitoring for particulate matter. 60.48c Reporting and recordkeeping requirements. Subpart Dc—Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units § 60.40c Applicability and delegation of authority.
(a)Except as provided in paragraph
(d)of this section, the affected facility to which this subpart applies is each steam generating unit for which construction, modification, or reconstruction is commenced after June 9, 1989 and that has a maximum design heat input capacity of 29 megawatts
(MW)(100 million British thermal units per hour (MMBtu/hr)) or less, but greater than or equal to 2.9 MW (10 MMBtu/hr).
(b)In delegating implementation and enforcement authority to a State under section 111(c) of the Clean Air Act, § 60.48c(a)(4) shall be retained by the Administrator and not transferred to a State.
(c)Steam generating units that meet the applicability requirements in paragraph
(a)of this section are not subject to the sulfur dioxide (SO <sup>2</sup> ) or particulate matter
(PM)emission limits, performance testing requirements, or monitoring requirements under this subpart (§§ 60.42c, 60.43c, 60.44c, 60.45c, 60.46c, or 60.47c) during periods of combustion research, as defined in § 60.41c.
(d)Any temporary change to an existing steam generating unit for the purpose of conducting combustion research is not considered a modification under § 60.14.
(e)Heat recovery steam generators that are associated with combined cycle gas turbines and meet the applicability requirements of subpart GG or KKKK of this part are not subject to this subpart. This subpart will continue to apply to all other heat recovery steam generators that are capable of combusting more than or equal to 2.9 MW (10 MMBtu/hr) heat input of fossil fuel but less than or equal to 29 MW (100 MMBtu/hr) heat input of fossil fuel. If the heat recovery steam generator is subject to this subpart, only emissions resulting from combustion of fuels in the steam generating unit are subject to this subpart. (The gas turbine emissions are subject to subpart GG or KKKK, as applicable, of this part).
(f)Any facility covered by subpart AAAA of this part is not covered by this subpart.
(g)Any facility covered by an EPA approved State or Federal section 111(d)/129 plan implementing subpart BBBB of this part is not covered by this subpart. § 60.41c Definitions. As used in this subpart, all terms not defined herein shall have the meaning given them in the Clean Air Act and in subpart A of this part. *Annual capacity factor* means the ratio between the actual heat input to a steam generating unit from an individual fuel or combination of fuels during a period of 12 consecutive calendar months and the potential heat input to the steam generating unit from all fuels had the steam generating unit been operated for 8,760 hours during that 12-month period at the maximum design heat input capacity. In the case of steam generating units that are rented or leased, the actual heat input shall be determined based on the combined heat input from all operations of the affected facility during a period of 12 consecutive calendar months. *Coal* means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17), coal refuse, and petroleum coke. Coal-derived synthetic fuels derived from coal for the purposes of creating useful heat, including but not limited to solvent refined coal, gasified coal, coal-oil mixtures, and coal-water mixtures, are also included in this definition for the purposes of this subpart. *Coal refuse* means any by-product of coal mining or coal cleaning operations with an ash content greater than 50 percent (by weight) and a heating value less than 13,900 kilojoules per kilogram (kJ/kg) (6,000 Btu per pound (Btu/lb) on a dry basis. *Cogeneration steam generating unit* means a steam generating unit that simultaneously produces both electrical (or mechanical) and thermal energy from the same primary energy source. *Combined cycle system* means a system in which a separate source (such as a stationary gas turbine, internal combustion engine, or kiln) provides exhaust gas to a steam generating unit. *Combustion research* means the experimental firing of any fuel or combination of fuels in a steam generating unit for the purpose of conducting research and development of more efficient combustion or more effective prevention or control of air pollutant emissions from combustion, provided that, during these periods of research and development, the heat generated is not used for any purpose other than preheating combustion air for use by that steam generating unit ( *i.e.* , the heat generated is released to the atmosphere without being used for space heating, process heating, driving pumps, preheating combustion air for other units, generating electricity, or any other purpose). *Conventional technology* means wet flue gas desulfurization technology, dry flue gas desulfurization technology, atmospheric fluidized bed combustion technology, and oil hydrodesulfurization technology. *Distillate oil* means fuel oil that complies with the specifications for fuel oil numbers 1 or 2, as defined by the American Society for Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17). *Dry flue gas desulfurization technology* means a SO <sup>2</sup> control system that is located between the steam generating unit and the exhaust vent or stack, and that removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline reagent and water, whether introduced separately or as a premixed slurry or solution and forming a dry powder material. This definition includes devices where the dry powder material is subsequently converted to another form. Alkaline reagents used in dry flue gas desulfurization systems include, but are not limited to, lime and sodium compounds. *Duct burner* means a device that combusts fuel and that is placed in the exhaust duct from another source (such as a stationary gas turbine, internal combustion engine, kiln, etc.) to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a steam generating unit. *Emerging technology* means any SO <sup>2</sup> control system that is not defined as a conventional technology under this section, and for which the owner or operator of the affected facility has received approval from the Administrator to operate as an emerging technology under § 60.48c(a)(4). *Federally enforceable* means all limitations and conditions that are enforceable by the Administrator, including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State implementation plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 51.24. *Fluidized bed combustion technology* means a device wherein fuel is distributed onto a bed (or series of beds) of limestone aggregate (or other sorbent materials) for combustion; and these materials are forced upward in the device by the flow of combustion air and the gaseous products of combustion. Fluidized bed combustion technology includes, but is not limited to, bubbling bed units and circulating bed units. *Fuel pretreatment* means a process that removes a portion of the sulfur in a fuel before combustion of the fuel in a steam generating unit. *Heat input* means heat derived from combustion of fuel in a steam generating unit and does not include the heat derived from preheated combustion air, recirculated flue gases, or exhaust gases from other sources (such as stationary gas turbines, internal combustion engines, and kilns). *Heat transfer medium* means any material that is used to transfer heat from one point to another point. *Maximum design heat input capacity* means the ability of a steam generating unit to combust a stated maximum amount of fuel (or combination of fuels) on a steady state basis as determined by the physical design and characteristics of the steam generating unit. *Natural gas* means:
(1)A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal constituent is methane; or
(2)liquefied petroleum
(LP)gas, as defined by the American Society for Testing and Materials in ASTM D1835 (incorporated by reference, see § 60.17). *Noncontinental area* means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern Mariana Islands. *Oil* means crude oil or petroleum, or a liquid fuel derived from crude oil or petroleum, including distillate oil and residual oil. *Potential sulfur dioxide emission rate* means the theoretical SO <sup>2</sup> emissions (nanograms per joule (ng/J) or lb/MMBtu heat input) that would result from combusting fuel in an uncleaned state and without using emission control systems. *Process heater* means a device that is primarily used to heat a material to initiate or promote a chemical reaction in which the material participates as a reactant or catalyst. *Residual oil* means crude oil, fuel oil that does not comply with the specifications under the definition of distillate oil, and all fuel oil numbers 4, 5, and 6, as defined by the American Society for Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17). *Steam generating unit* means a device that combusts any fuel and produces steam or heats water or any other heat transfer medium. This term includes any duct burner that combusts fuel and is part of a combined cycle system. This term does not include process heaters as defined in this subpart. *Steam generating unit operating day* means a 24-hour period between 12:00 midnight and the following midnight during which any fuel is combusted at any time in the steam generating unit. It is not necessary for fuel to be combusted continuously for the entire 24-hour period. *Wet flue gas desulfurization technology* means an SO <sup>2</sup> control system that is located between the steam generating unit and the exhaust vent or stack, and that removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline slurry or solution and forming a liquid material. This definition includes devices where the liquid material is subsequently converted to another form. Alkaline reagents used in wet flue gas desulfurization systems include, but are not limited to, lime, limestone, and sodium compounds. *Wet scrubber system* means any emission control device that mixes an aqueous stream or slurry with the exhaust gases from a steam generating unit to control emissions of PM or SO <sup>2</sup> . *Wood* means wood, wood residue, bark, or any derivative fuel or residue thereof, in any form, including but not limited to sawdust, sanderdust, wood chips, scraps, slabs, millings, shavings, and processed pellets made from wood or other forest residues. § 60.42c Standard for sulfur dioxide (SO <sup>2</sup> ).
(a)Except as provided in paragraphs (b), (c), and
(e)of this section, on and after the date on which the performance test is completed or required to be completed under § 60.8, whichever date comes first, the owner or operator of an affected facility that combusts only coal shall neither: cause to be discharged into the atmosphere from the affected facility any gases that contain SO <sup>2</sup> in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO <sup>2</sup> emission rate (90 percent reduction), nor cause to be discharged into the atmosphere from the affected facility any gases that contain SO <sup>2</sup> in excess of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is combusted with other fuels, the affected facility shall neither: cause to be discharged into the atmosphere from the affected facility any gases that contain SO <sup>2</sup> in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO <sup>2</sup> emission rate (90 percent reduction), nor cause to be discharged into the atmosphere from the affected facility any gases that contain SO <sup>2</sup> in excess of the emission limit is determined pursuant to paragraph (e)(2) of this section.
(b)Except as provided in paragraphs
(c)and
(e)of this section, on and after the date on which the performance test is completed or required to be completed under § 60.8, whichever date comes first, the owner or operator of an affected facility that:
(1)Combusts only coal refuse alone in a fluidized bed combustion steam generating unit shall neither:
(i)Cause to be discharged into the atmosphere from that affected facility any gases that contain SO <sup>2</sup> in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 20 percent (0.20) of the potential SO <sup>2</sup> emission rate (80 percent reduction); nor
(ii)Cause to be discharged into the atmosphere from that affected facility any gases that contain SO <sup>2</sup> in excess of SO <sup>2</sup> in excess of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is fired with coal refuse, the affected facility subject to paragraph
(a)of this section. If oil or any other fuel (except coal) is fired with coal refuse, the affected facility is subject to the 87 ng/J (0.20 lb/MMBtu) heat input SO <sup>2</sup> emissions limit or the 90 percent SO <sup>2</sup> reduction requirement specified in paragraph
(a)of this section and the emission limit is determined pursuant to paragraph (e)(2) of this section.
(2)Combusts only coal and that uses an emerging technology for the control of SO <sup>2</sup> emissions shall neither:
(i)Cause to be discharged into the atmosphere from that affected facility any gases that contain SO <sup>2</sup> in excess of 50 percent (0.50) of the potential SO <sup>2</sup> emission rate (50 percent reduction); nor
(ii)Cause to be discharged into the atmosphere from that affected facility any gases that contain SO <sup>2</sup> in excess of 260 ng/J (0.60 lb/MMBtu) heat input. If coal is combusted with other fuels, the affected facility is subject to the 50 percent SO <sup>2</sup> reduction requirement specified in this paragraph and the emission limit determined pursuant to paragraph (e)(2) of this section.
(c)On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that combusts coal, alone or in combination with any other fuel, and is listed in paragraphs (c)(1), (2), (3), or
(4)of this section shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO <sup>2</sup> in excess of the emission limit determined pursuant to paragraph (e)(2) of this section. Percent reduction requirements are not applicable to affected facilities under paragraphs (c)(1), (2), (3), or (4).
(1)Affected facilities that have a heat input capacity of 22 MW (75 MMBtu/hr) or less.
(2)Affected facilities that have an annual capacity for coal of 55 percent (0.55) or less and are subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor for coal of 55 percent (0.55) or less.
(3)Affected facilities located in a noncontinental area.
(4)Affected facilities that combust coal in a duct burner as part of a combined cycle system where 30 percent (0.30) or less of the heat entering the steam generating unit is from combustion of coal in the duct burner and 70 percent (0.70) or more of the heat entering the steam generating unit is from exhaust gases entering the duct burner.
(d)On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that combusts oil shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO <sup>2</sup> in excess of 215 ng/J (0.50 lb/MMBtu) heat input; or, as an alternative, no owner or operator of an affected facility that combusts oil shall combust oil in the affected facility that contains greater than 0.5 weight percent sulfur. The percent reduction requirements are not applicable to affected facilities under this paragraph.
(e)On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that combusts coal, oil, or coal and oil with any other fuel shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO <sup>2</sup> in excess of the following:
(1)The percent of potential SO <sup>2</sup> emission rate or numerical SO <sup>2</sup> emission rate required under paragraph
(a)or (b)(2) of this section, as applicable, for any affected facility that
(i)Combusts coal in combination with any other fuel;
(ii)Has a heat input capacity greater than 22 MW (75 MMBtu/hr); and
(iii)Has an annual capacity factor for coal greater than 55 percent (0.55); and
(2)The emission limit determined according to the following formula for any affected facility that combusts coal, oil, or coal and oil with any other fuel: ER13JN07.032 Where: E <sup>s</sup> = SO <sup>2</sup> emission limit, expressed in ng/J or lb/MMBtu heat input; K <sup>a</sup> = 520 ng/J (1.2 lb/MMBtu); K <sup>b</sup> = 260 ng/J (0.60 lb/MMBtu); K <sup>c</sup> = 215 ng/J (0.50 lb/MMBtu); H <sup>a</sup> = Heat input from the combustion of coal, except coal combusted in an affected facility subject to paragraph (b)(2) of this section, in Joules
(J)[MMBtu]; H <sup>b</sup> = Heat input from the combustion of coal in an affected facility subject to paragraph (b)(2) of this section, in J (MMBtu); and H <sup>c</sup> K <sup>a</sup> H <sup>b</sup> = Heat input from the combustion of oil, in J (MMBtu).
(f)Reduction in the potential SO <sup>2</sup> emission rate through fuel pretreatment is not credited toward the percent reduction requirement under paragraph (b)(2) of this section unless:
(1)Fuel pretreatment results in a 50 percent (0.50) or greater reduction in the potential SO <sup>2</sup> emission rate; and
(2)Emissions from the pretreated fuel (without either combustion or post-combustion SO <sup>2</sup> control) are equal to or less than the emission limits specified under paragraph (b)(2) of this section.
(g)Except as provided in paragraph
(h)of this section, compliance with the percent reduction requirements, fuel oil sulfur limits, and emission limits of this section shall be determined on a 30-day rolling average basis.
(h)For affected facilities listed under paragraphs (h)(1), (2), or
(3)of this section, compliance with the emission limits or fuel oil sulfur limits under this section may be determined based on a certification from the fuel supplier, as described under § 60.48c(f), as applicable.
(1)Distillate oil-fired affected facilities with heat input capacities between 2.9 and 29 MW (10 and 100 MMBtu/hr).
(2)Residual oil-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).
(3)Coal-fired facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).
(i)The SO <sup>2</sup> emission limits, fuel oil sulfur limits, and percent reduction requirements under this section apply at all times, including periods of startup, shutdown, and malfunction.
(j)Only the heat input supplied to the affected facility from the combustion of coal and oil is counted under this section. No credit is provided for the heat input to the affected facility from wood or other fuels or for heat derived from exhaust gases from other sources, such as stationary gas turbines, internal combustion engines, and kilns. § 60.43c Standard for particulate matter (PM).
(a)On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, that combusts coal or combusts mixtures of coal with other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/hr) or greater, shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of the following emission limits:
(1)22 ng/J (0.051 lb/MMBtu) heat input if the affected facility combusts only coal, or combusts coal with other fuels and has an annual capacity factor for the other fuels of 10 percent (0.10) or less.
(2)43 ng/J (0.10 lb/MMBtu) heat input if the affected facility combusts coal with other fuels, has an annual capacity factor for the other fuels greater than 10 percent (0.10), and is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor greater than 10 percent (0.10) for fuels other than coal.
(b)On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, that combusts wood or combusts mixtures of wood with other fuels (except coal) and has a heat input capacity of 8.7 MW (30 MMBtu/hr) or greater, shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of the following emissions limits:
(1)43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has an annual capacity factor for wood greater than 30 percent (0.30); or
(2)130 ng/J (0.30 lb/MMBtu) heat input if the affected facility has an annual capacity factor for wood of 30 percent (0.30) or less and is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor for wood of 30 percent (0.30) or less.
(c)On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that combusts coal, wood, or oil and has a heat input capacity of 8.7 MW (30 MMBtu/hr) or greater shall cause to be discharged into the atmosphere from that affected facility any gases that exhibit greater than 20 percent opacity (6-minute average), except for one 6-minute period per hour of not more than 27 percent opacity.
(d)The PM and opacity standards under this section apply at all times, except during periods of startup, shutdown, or malfunction. (e)(1) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commences construction, reconstruction, or modification after February 28, 2005, and that combusts coal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/hr) or greater shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input, except as provided in paragraphs (e)(2), (e)(3), and (e)(4) of this section.
(2)As an alternative to meeting the requirements of paragraph (e)(1) of this section, the owner or operator of an affected facility for which modification commenced after February 28, 2005, may elect to meet the requirements of this paragraph. On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commences modification after February 28, 2005 shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of both:
(i)22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion of coal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels; and
(ii)0.2 percent of the combustion concentration (99.8 percent reduction) when combusting coal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels.
(3)On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commences modification after February 28, 2005, and that combusts over 30 percent wood (by heat input) on an annual basis and has a heat input capacity of 8.7 MW (30 MMBtu/hr) or greater shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.
(4)On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, an owner or operator of an affected facility that commences construction, reconstruction, or modification after February 28, 2005, and that combusts only oil that contains no more than 0.50 weight percent sulfur or a mixture of 0.50 weight percent sulfur oil with other fuels not subject to a PM standard under § 60.43c and not using a post-combustion technology (except a wet scrubber) to reduce PM or SO <sup>2</sup> emissions is not subject to the PM limit in this section. § 60.44c Compliance and performance test methods and procedures for sulfur dioxide.
(a)Except as provided in paragraphs
(g)and
(h)of this section and § 60.8(b), performance tests required under § 60.8 shall be conducted following the procedures specified in paragraphs (b), (c), (d), (e), and
(f)of this section, as applicable. Section 60.8(f) does not apply to this section. The 30-day notice required in § 60.8(d) applies only to the initial performance test unless otherwise specified by the Administrator.
(b)The initial performance test required under § 60.8 shall be conducted over 30 consecutive operating days of the steam generating unit. Compliance with the percent reduction requirements and SO <sup>2</sup> emission limits under § 60.42c shall be determined using a 30-day average. The first operating day included in the initial performance test shall be scheduled within 30 days after achieving the maximum production rate at which the affect facility will be operated, but not later than 180 days after the initial startup of the facility. The steam generating unit load during the 30-day period does not have to be the maximum design heat input capacity, but must be representative of future operating conditions.
(c)After the initial performance test required under paragraph
(b)of this section and § 60.8, compliance with the percent reduction requirements and SO <sup>2</sup> emission limits under § 60.42c is based on the average percent reduction and the average SO <sup>2</sup> emission rates for 30 consecutive steam generating unit operating days. A separate performance test is completed at the end of each steam generating unit operating day, and a new 30-day average percent reduction and SO <sup>2</sup> emission rate are calculated to show compliance with the standard.
(d)If only coal, only oil, or a mixture of coal and oil is combusted in an affected facility, the procedures in Method 19 of appendix A of this part are used to determine the hourly SO <sup>2</sup> emission rate (E <sup>ho</sup> ) and the 30-day average SO <sup>2</sup> emission rate (E <sup>ao</sup> ). The hourly averages used to compute the 30-day averages are obtained from the CEMS. Method 19 of appendix A of this part shall be used to calculate E <sup>ao</sup> when using daily fuel sampling or Method 6B of appendix A of this part.
(e)If coal, oil, or coal and oil are combusted with other fuels:
(1)An adjusted E <sup>ho</sup> (E <sup>ho</sup> o) is used in Equation 19-19 of Method 19 of appendix A of this part to compute the adjusted E <sup>ao</sup> (E <sup>ao</sup> o). The E <sup>ho</sup> o is computed using the following formula: ER13JN07.033 Where: E <sup>ho</sup> o = Adjusted E <sup>ho</sup> , ng/J (lb/MMBtu); E <sup>ho</sup> = Hourly SO <sup>2</sup> emission rate, ng/J (lb/MMBtu); E <sup>w</sup> = SO <sup>2</sup> concentration in fuels other than coal and oil combusted in the affected facility, as determined by fuel sampling and analysis procedures in Method 9 of appendix A of this part, ng/J (lb/MMBtu). The value E <sup>w</sup> for each fuel lot is used for each hourly average during the time that the lot is being combusted. The owner or operator does not have to measure E <sup>w</sup> if the owner or operator elects to assume E <sup>w</sup> = 0. X <sup>k</sup> = Fraction of the total heat input from fuel combustion derived from coal and oil, as determined by applicable procedures in Method 19 of appendix A of this part.
(2)The owner or operator of an affected facility that qualifies under the provisions of § 60.42c(c) or
(d)(where percent reduction is not required) does not have to measure the parameters E <sup>w</sup> or X <sup>k</sup> if the owner or operator of the affected facility elects to measure emission rates of the coal or oil using the fuel sampling and analysis procedures under Method 19 of appendix A of this part.
(f)Affected facilities subject to the percent reduction requirements under § 60.42c(a) or
(b)shall determine compliance with the SO <sup>2</sup> emission limits under § 60.42c pursuant to paragraphs
(d)or
(e)of this section, and shall determine compliance with the percent reduction requirements using the following procedures:
(1)If only coal is combusted, the percent of potential SO <sup>2</sup> emission rate is computed using the following formula: ER13JN07.034 Where: %P <sup>s</sup> = Potential SO <sup>2</sup> emission rate, in percent; %R <sup>g</sup> = SO <sup>2</sup> removal efficiency of the control device as determined by Method 19 of appendix A of this part, in percent; and %R <sup>f</sup> = SO <sup>2</sup> removal efficiency of fuel pretreatment as determined by Method 19 of appendix A of this part, in percent.
(2)If coal, oil, or coal and oil are combusted with other fuels, the same procedures required in paragraph (f)(1) of this section are used, except as provided for in the following:
(i)To compute the %P <sup>s</sup> , an adjusted %R <sup>g</sup> (%R <sup>g</sup> o) is computed from E <sup>ao</sup> o from paragraph (e)(1) of this section and an adjusted average SO <sup>2</sup> inlet rate (E <sup>ai</sup> o) using the following formula: ER13JN07.035 Where: %R <sup>g</sup> o = Adjusted %R <sup>g</sup> , in percent; E <sup>ao</sup> o = Adjusted E <sup>ao</sup> , ng/J (lb/MMBtu); and E <sup>ai</sup> o = Adjusted average SO <sup>2</sup> inlet rate, ng/J (lb/MMBtu).
(ii)To compute E <sup>ai</sup> o, an adjusted hourly SO <sup>2</sup> inlet rate (E <sup>hi</sup> o) is used. The E <sup>hi</sup> o is computed using the following formula: ER13JN07.036 Where: E <sup>hi</sup> o = Adjusted E <sup>hi</sup> , ng/J (lb/MMBtu); E <sup>hi</sup> = Hourly SO <sup>2</sup> inlet rate, ng/J (lb/MMBtu); E <sup>w</sup> = SO <sup>2</sup> concentration in fuels other than coal and oil combusted in the affected facility, as determined by fuel sampling and analysis procedures in Method 19 of appendix A of this part, ng/J (lb/MMBtu). The value E <sup>w</sup> for each fuel lot is used for each hourly average during the time that the lot is being combusted. The owner or operator does not have to measure E <sup>w</sup> if the owner or operator elects to assume E <sup>w</sup> = 0; and X <sup>k</sup> = Fraction of the total heat input from fuel combustion derived from coal and oil, as determined by applicable procedures in Method 19 of appendix A of this part.
(g)For oil-fired affected facilities where the owner or operator seeks to demonstrate compliance with the fuel oil sulfur limits under § 60.42c based on shipment fuel sampling, the initial performance test shall consist of sampling and analyzing the oil in the initial tank of oil to be fired in the steam generating unit to demonstrate that the oil contains 0.5 weight percent sulfur or less. Thereafter, the owner or operator of the affected facility shall sample the oil in the fuel tank after each new shipment of oil is received, as described under § 60.46c(d)(2).
(h)For affected facilities subject to § 60.42c(h)(1), (2), or
(3)where the owner or operator seeks to demonstrate compliance with the SO <sup>2</sup> standards based on fuel supplier certification, the performance test shall consist of the certification, the certification from the fuel supplier, as described under § 60.48c(f), as applicable.
(i)The owner or operator of an affected facility seeking to demonstrate compliance with the SO <sup>2</sup> standards under § 60.42c(c)(2) shall demonstrate the maximum design heat input capacity of the steam generating unit by operating the steam generating unit at this capacity for 24 hours. This demonstration shall be made during the initial performance test, and a subsequent demonstration may be requested at any other time. If the demonstrated 24-hour average firing rate for the affected facility is less than the maximum design heat input capacity stated by the manufacturer of the affected facility, the demonstrated 24-hour average firing rate shall be used to determine the annual capacity factor for the affected facility; otherwise, the maximum design heat input capacity provided by the manufacturer shall be used.
(j)The owner or operator of an affected facility shall use all valid SO <sup>2</sup> emissions data in calculating %P <sup>s</sup> and E <sup>ho</sup> under paragraphs (d), (e), or
(f)of this section, as applicable, whether or not the minimum emissions data requirements under § 60.46c(f) are achieved. All valid emissions data, including valid data collected during periods of startup, shutdown, and malfunction, shall be used in calculating %P <sup>s</sup> or E <sup>ho</sup> pursuant to paragraphs (d), (e), or
(f)of this section, as applicable. § 60.45c Compliance and performance test methods and procedures for particulate matter.
(a)The owner or operator of an affected facility subject to the PM and/or opacity standards under § 60.43c shall conduct an initial performance test as required under § 60.8, and shall conduct subsequent performance tests as requested by the Administrator, to determine compliance with the standards using the following procedures and reference methods, except as specified in paragraph
(c)of this section.
(1)Method 1 of appendix A of this part shall be used to select the sampling site and the number of traverse sampling points.
(2)Method 3 of appendix A of this part shall be used for gas analysis when applying Method 5, 5B, or 17 of appendix A of this part.
(3)Method 5, 5B, or 17 of appendix A of this part shall be used to measure the concentration of PM as follows:
(i)Method 5 of appendix A of this part may be used only at affected facilities without wet scrubber systems.
(ii)Method 17 of appendix A of this part may be used at affected facilities with or without wet scrubber systems provided the stack gas temperature does not exceed a temperature of 160 °C (320 °F). The procedures of Sections 8.1 and 11.1 of Method 5B of appendix A of this part may be used in Method 17 of appendix A of this part only if Method 17 of appendix A of this part is used in conjunction with a wet scrubber system. Method 17 of appendix A of this part shall not be used in conjunction with a wet scrubber system if the effluent is saturated or laden with water droplets.
(iii)Method 5B of appendix A of this part may be used in conjunction with a wet scrubber system.
(4)The sampling time for each run shall be at least 120 minutes and the minimum sampling volume shall be 1.7 dry standard cubic meters
(dscm)[60 dry standard cubic feet (dscf)] except that smaller sampling times or volumes may be approved by the Administrator when necessitated by process variables or other factors.
(5)For Method 5 or 5B of appendix A of this part, the temperature of the sample gas in the probe and filter holder shall be monitored and maintained at 160 ±14 °C (320±25 °F).
(6)For determination of PM emissions, an oxygen (O <sup>2</sup> ) or carbon dioxide (CO <sup>2</sup> ) measurement shall be obtained simultaneously with each run of Method 5, 5B, or 17 of appendix A of this part by traversing the duct at the same sampling location.
(7)For each run using Method 5, 5B, or 17 of appendix A of this part, the emission rates expressed in ng/J (lb/MMBtu) heat input shall be determined using:
(i)The O <sup>2</sup> or CO <sup>2</sup> measurements and PM measurements obtained under this section,
(ii)The dry basis F factor, and
(iii)The dry basis emission rate calculation procedure contained in Method 19 of appendix A of this part.
(8)Method 9 of appendix A of this part (6-minute average of 24 observations) shall be used for determining the opacity of stack emissions.
(b)The owner or operator of an affected facility seeking to demonstrate compliance with the PM standards under § 60.43c(b)(2) shall demonstrate the maximum design heat input capacity of the steam generating unit by operating the steam generating unit at this capacity for 24 hours. This demonstration shall be made during the initial performance test, and a subsequent demonstration may be requested at any other time. If the demonstrated 24-hour average firing rate for the affected facility is less than the maximum design heat input capacity stated by the manufacturer of the affected facility, the demonstrated 24-hour average firing rate shall be used to determine the annual capacity factor for the affected facility; otherwise, the maximum design heat input capacity provided by the manufacturer shall be used.
(c)In place of PM testing with EPA Reference Method 5, 5B, or 17 of appendix A of this part, an owner or operator may elect to install, calibrate, maintain, and operate a CEMS for monitoring PM emissions discharged to the atmosphere and record the output of the system. The owner or operator of an affected facility who elects to continuously monitor PM emissions instead of conducting performance testing using EPA Method 5, 5B, or 17 of appendix A of this part shall install, calibrate, maintain, and operate a CEMS and shall comply with the requirements specified in paragraphs (c)(1) through (c)(13) of this section.
(1)Notify the Administrator 1 month before starting use of the system.
(2)Notify the Administrator 1 month before stopping use of the system.
(3)The monitor shall be installed, evaluated, and operated in accordance with § 60.13 of subpart A of this part.
(4)The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the affected facility, as specified under § 60.8 of subpart A of this part or within 180 days of notification to the Administrator of use of CEMS if the owner or operator was previously determining compliance by Method 5, 5B, or 17 of appendix A of this part performance tests, whichever is later.
(5)The owner or operator of an affected facility shall conduct an initial performance test for PM emissions as required under § 60.8 of subpart A of this part. Compliance with the PM emission limit shall be determined by using the CEMS specified in paragraph
(d)of this section to measure PM and calculating a 24-hour block arithmetic average emission concentration using EPA Reference Method 19 of appendix A of this part, section 4.1.
(6)Compliance with the PM emission limit shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average emission concentrations using CEMS outlet data.
(7)At a minimum, valid CEMS hourly averages shall be obtained as specified in paragraph (d)(7)(i) of this section for 75 percent of the total operating hours per 30-day rolling average.
(i)At least two data points per hour shall be used to calculate each 1-hour arithmetic average.
(ii)[Reserved]
(8)The 1-hour arithmetic averages required under paragraph (d)(7) of this section shall be expressed in ng/J or lb/MMBtu heat input and shall be used to calculate the boiler operating day daily arithmetic average emission concentrations. The 1-hour arithmetic averages shall be calculated using the data points required under § 60.13(e)(2) of subpart A of this part.
(9)All valid CEMS data shall be used in calculating average emission concentrations even if the minimum CEMS data requirements of paragraph (d)(7) of this section are not met.
(10)The CEMS shall be operated according to Performance Specification 11 in appendix B of this part.
(11)During the correlation testing runs of the CEMS required by Performance Specification 11 in appendix B of this part, PM and O <sup>2</sup> (or CO <sup>2</sup> ) data shall be collected concurrently (or within a 30- to 60-minute period) by both the continuous emission monitors and the test methods specified in paragraph (d)(7)(i) of this section.
(i)For PM, EPA Reference Method 5, 5B, or 17 of appendix A of this part shall be used.
(ii)For O <sup>2</sup> (or CO <sup>2</sup> ), EPA reference Method 3, 3A, or 3B of appendix A of this part, as applicable shall be used.
(12)Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 2 in appendix F of this part. Relative Response Audit's must be performed annually and Response Correlation Audits must be performed every 3 years.
(13)When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by the Administrator or EPA Reference Method 19 of appendix A of this part to provide, as necessary, valid emissions data for a minimum of 75 percent of total operating hours on a 30-day rolling average.
(d)The owner or operator of an affected facility seeking to demonstrate compliance under § 60.43c(e)(4) shall follow the applicable procedures under § 60.48c(f). For residual oil-fired affected facilities, fuel supplier certifications are only allowed for facilities with heat input capacities between 2.9 and 8.7 MW (10 to 30 MMBtu/hr). § 60.46c Emission monitoring for sulfur dioxide.
(a)Except as provided in paragraphs
(d)and
(e)of this section, the owner or operator of an affected facility subject to the SO <sup>2</sup> emission limits under § 60.42c shall install, calibrate, maintain, and operate a CEMS for measuring SO <sup>2</sup> concentrations and either O <sup>2</sup> or CO <sup>2</sup> concentrations at the outlet of the SO <sup>2</sup> control device (or the outlet of the steam generating unit if no SO <sup>2</sup> control device is used), and shall record the output of the system. The owner or operator of an affected facility subject to the percent reduction requirements under § 60.42c shall measure SO <sup>2</sup> concentrations and either O <sup>2</sup> or CO <sup>2</sup> concentrations at both the inlet and outlet of the SO <sup>2</sup> control device.
(b)The 1-hour average SO <sup>2</sup> emission rates measured by a CEMS shall be expressed in ng/J or lb/MMBtu heat input and shall be used to calculate the average emission rates under § 60.42c. Each 1-hour average SO <sup>2</sup> emission rate must be based on at least 30 minutes of operation, and shall be calculated using the data points required under § 60.13(h)(2). Hourly SO <sup>2</sup> emission rates are not calculated if the affected facility is operated less than 30 minutes in a 1-hour period and are not counted toward determination of a steam generating unit operating day.
(c)The procedures under § 60.13 shall be followed for installation, evaluation, and operation of the CEMS.
(1)All CEMS shall be operated in accordance with the applicable procedures under Performance Specifications 1, 2, and 3 of appendix B of this part.
(2)Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with Procedure 1 of appendix F of this part.
(3)For affected facilities subject to the percent reduction requirements under § 60.42c, the span value of the SO <sup>2</sup> CEMS at the inlet to the SO <sup>2</sup> control device shall be 125 percent of the maximum estimated hourly potential SO <sup>2</sup> emission rate of the fuel combusted, and the span value of the SO <sup>2</sup> CEMS at the outlet from the SO <sup>2</sup> control device shall be 50 percent of the maximum estimated hourly potential SO <sup>2</sup> emission rate of the fuel combusted.
(4)For affected facilities that are not subject to the percent reduction requirements of § 60.42c, the span value of the SO <sup>2</sup> CEMS at the outlet from the SO <sup>2</sup> control device (or outlet of the steam generating unit if no SO <sup>2</sup> control device is used) shall be 125 percent of the maximum estimated hourly potential SO <sup>2</sup> emission rate of the fuel combusted.
(d)As an alternative to operating a CEMS at the inlet to the SO <sup>2</sup> control device (or outlet of the steam generating unit if no SO <sup>2</sup> control device is used) as required under paragraph
(a)of this section, an owner or operator may elect to determine the average SO <sup>2</sup> emission rate by sampling the fuel prior to combustion. As an alternative to operating a CEMS at the outlet from the SO <sup>2</sup> control device (or outlet of the steam generating unit if no SO <sup>2</sup> control device is used) as required under paragraph
(a)of this section, an owner or operator may elect to determine the average SO <sup>2</sup> emission rate by using Method 6B of appendix A of this part. Fuel sampling shall be conducted pursuant to either paragraph (d)(1) or (d)(2) of this section. Method 6B of appendix A of this part shall be conducted pursuant to paragraph (d)(3) of this section.
(1)For affected facilities combusting coal or oil, coal or oil samples shall be collected daily in an as-fired condition at the inlet to the steam generating unit and analyzed for sulfur content and heat content according the Method 19 of appendix A of this part. Method 19 of appendix A of this part provides procedures for converting these measurements into the format to be used in calculating the average SO <sup>2</sup> input rate.
(2)As an alternative fuel sampling procedure for affected facilities combusting oil, oil samples may be collected from the fuel tank for each steam generating unit immediately after the fuel tank is filled and before any oil is combusted. The owner or operator of the affected facility shall analyze the oil sample to determine the sulfur content of the oil. If a partially empty fuel tank is refilled, a new sample and analysis of the fuel in the tank would be required upon filling. Results of the fuel analysis taken after each new shipment of oil is received shall be used as the daily value when calculating the 30-day rolling average until the next shipment is received. If the fuel analysis shows that the sulfur content in the fuel tank is greater than 0.5 weight percent sulfur, the owner or operator shall ensure that the sulfur content of subsequent oil shipments is low enough to cause the 30-day rolling average sulfur content to be 0.5 weight percent sulfur or less.
(3)Method 6B of appendix A of this part may be used in lieu of CEMS to measure SO <sup>2</sup> at the inlet or outlet of the SO <sup>2</sup> control system. An initial stratification test is required to verify the adequacy of the Method 6B of appendix A of this part sampling location. The stratification test shall consist of three paired runs of a suitable SO <sup>2</sup> and CO <sup>2</sup> measurement train operated at the candidate location and a second similar train operated according to the procedures in § 3.2 and the applicable procedures in section 7 of Performance Specification 2 of appendix B of this part. Method 6B of appendix A of this part, Method 6A of appendix A of this part, or a combination of Methods 6 and 3 of appendix A of this part or Methods 6C and 3A of appendix A of this part are suitable measurement techniques. If Method 6B of appendix A of this part is used for the second train, sampling time and timer operation may be adjusted for the stratification test as long as an adequate sample volume is collected; however, both sampling trains are to be operated similarly. For the location to be adequate for Method 6B of appendix A of this part 24-hour tests, the mean of the absolute difference between the three paired runs must be less than 10 percent (0.10).
(e)The monitoring requirements of paragraphs
(a)and
(d)of this section shall not apply to affected facilities subject to § 60.42c(h) (1), (2), or
(3)where the owner or operator of the affected facility seeks to demonstrate compliance with the SO <sup>2</sup> standards based on fuel supplier certification, as described under § 60.48c(f), as applicable.
(f)The owner or operator of an affected facility operating a CEMS pursuant to paragraph
(a)of this section, or conducting as-fired fuel sampling pursuant to paragraph (d)(1) of this section, shall obtain emission data for at least 75 percent of the operating hours in at least 22 out of 30 successive steam generating unit operating days. If this minimum data requirement is not met with a single monitoring system, the owner or operator of the affected facility shall supplement the emission data with data collected with other monitoring systems as approved by the Administrator. § 60.47c Emission monitoring for particulate matter.
(a)Except as provided in paragraphs (c), (d), (e), and
(f)of this section, the owner or operator of an affected facility combusting coal, oil, or wood that is subject to the opacity standards under § 60.43c shall install, calibrate, maintain, and operate a COMS for measuring the opacity of the emissions discharged to the atmosphere and record the output of the system.
(b)All COMS for measuring opacity shall be operated in accordance with the applicable procedures under Performance Specification 1 of appendix B of this part. The span value of the opacity COMS shall be between 60 and 80 percent.
(c)Affected facilities that burn only distillate oil that contains no more than 0.5 weight percent sulfur and/or liquid or gaseous fuels with potential sulfur dioxide emission rates of 26 ng/J (0.06 lb/MMBtu) heat input or less and that do not use a post-combustion technology to reduce SO <sup>2</sup> or PM emissions are not required to operate a CEMS for measuring opacity if they follow the applicable procedures under § 60.48c(f).
(d)Owners or operators complying with the PM emission limit by using a PM CEMS monitor instead of monitoring opacity must calibrate, maintain, and operate a CEMS, and record the output of the system, for PM emissions discharged to the atmosphere as specified in § 60.45c(d). The CEMS specified in paragraph § 60.45c(d) shall be operated and data recorded during all periods of operation of the affected facility except for CEMS breakdowns and repairs. Data is recorded during calibration checks, and zero and span adjustments.
(e)An affected facility that does not use post-combustion technology (except a wet scrubber) for reducing PM, SO <sup>2</sup> , or carbon monoxide
(CO)emissions, burns only gaseous fuels or fuel oils that contain less than or equal to 0.5 weight percent sulfur, and is operated such that emissions of CO to the atmosphere from the affected facility are maintained at levels less than or equal to 0.15 lb/MMBtu on a boiler operating day average basis is not required to operate a COMS for measuring opacity. Owners and operators of affected facilities electing to comply with this paragraph must demonstrate compliance according to the procedures specified in paragraphs (e)(1) through
(4)of this section.
(1)You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs (e)(1)(i) through
(iv)of this section.
(i)The CO CEMS must be installed, certified, maintained, and operated according to the provisions in § 60.58b(i)(3) of subpart Eb of this part.
(ii)Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis).
(iii)At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-day rolling average basis. At least two data points per hour must be used to calculate each 1-hour average.
(iv)Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be performed in accordance with procedure 1 in appendix F of this part.
(2)You must calculate the 1-hour average CO emissions levels for each steam generating unit operating day by multiplying the average hourly CO output concentration measured by the CO CEMS times the corresponding average hourly flue gas flow rate and divided by the corresponding average hourly heat input to the affected source. The 24-hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission levels computed for each steam generating unit operating day.
(3)You must evaluate the preceding 24-hour average CO emission level each steam generating unit operating day excluding periods of affected source startup, shutdown, or malfunction. If the 24-hour average CO emission level is greater than 0.15 lb/MMBtu, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of the high emission incident and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 0.15 lb/MMBtu or less.
(4)You must record the CO measurements and calculations performed according to paragraph
(e)of this section and any corrective actions taken. The record of corrective action taken must include the date and time during which the 24-hour average CO emission level was greater than 0.15 lb/MMBtu, and the date, time, and description of the corrective action.
(f)An affected facility that burns only gaseous fuels or fuel oils that contain less than or equal to 0.5 weight percent sulfur and operates according to a written site-specific monitoring plan approved by the appropriate delegated permitting authority is not required to operate a COMS for measuring opacity. This monitoring plan must include procedures and criteria for establishing and monitoring specific parameters for the affected facility indicative of compliance with the opacity standard. § 60.48c Reporting and recordkeeping requirements.
(a)The owner or operator of each affected facility shall submit notification of the date of construction or reconstruction and actual startup, as provided by § 60.7 of this part. This notification shall include:
(1)The design heat input capacity of the affected facility and identification of fuels to be combusted in the affected facility.
(2)If applicable, a copy of any federally enforceable requirement that limits the annual capacity factor for any fuel or mixture of fuels under § 60.42c, or § 60.43c.
(3)The annual capacity factor at which the owner or operator anticipates operating the affected facility based on all fuels fired and based on each individual fuel fired.
(4)Notification if an emerging technology will be used for controlling SO <sup>2</sup> emissions. The Administrator will examine the description of the control device and will determine whether the technology qualifies as an emerging technology. In making this determination, the Administrator may require the owner or operator of the affected facility to submit additional information concerning the control device. The affected facility is subject to the provisions of § 60.42c(a) or (b)(1), unless and until this determination is made by the Administrator.
(b)The owner or operator of each affected facility subject to the SO <sup>2</sup> emission limits of § 60.42c, or the PM or opacity limits of § 60.43c, shall submit to the Administrator the performance test data from the initial and any subsequent performance tests and, if applicable, the performance evaluation of the CEMS and/or COMS using the applicable performance specifications in appendix B of this part.
(c)The owner or operator of each coal-fired, oil-fired, or wood-fired affected facility subject to the opacity limits under § 60.43c(c) shall submit excess emission reports for any excess emissions from the affected facility that occur during the reporting period.
(d)The owner or operator of each affected facility subject to the SO <sup>2</sup> emission limits, fuel oil sulfur limits, or percent reduction requirements under § 60.42c shall submit reports to the Administrator.
(e)The owner or operator of each affected facility subject to the SO <sup>2</sup> emission limits, fuel oil sulfur limits, or percent reduction requirements under § 60.42c shall keep records and submit reports as required under paragraph
(d)of this section, including the following information, as applicable.
(1)Calendar dates covered in the reporting period.
(2)Each 30-day average SO <sup>2</sup> emission rate (ng/J or lb/MMBtu), or 30-day average sulfur content (weight percent), calculated during the reporting period, ending with the last 30-day period; reasons for any noncompliance with the emission standards; and a description of corrective actions taken.
(3)Each 30-day average percent of potential SO <sup>2</sup> emission rate calculated during the reporting period, ending with the last 30-day period; reasons for any noncompliance with the emission standards; and a description of the corrective actions taken.
(4)Identification of any steam generating unit operating days for which SO <sup>2</sup> or diluent (O <sup>2</sup> or CO <sup>2</sup> ) data have not been obtained by an approved method for at least 75 percent of the operating hours; justification for not obtaining sufficient data; and a description of corrective actions taken.
(5)Identification of any times when emissions data have been excluded from the calculation of average emission rates; justification for excluding data; and a description of corrective actions taken if data have been excluded for periods other than those during which coal or oil were not combusted in the steam generating unit.
(6)Identification of the F factor used in calculations, method of determination, and type of fuel combusted.
(7)Identification of whether averages have been obtained based on CEMS rather than manual sampling methods.
(8)If a CEMS is used, identification of any times when the pollutant concentration exceeded the full span of the CEMS.
(9)If a CEMS is used, description of any modifications to the CEMS that could affect the ability of the CEMS to comply with Performance Specifications 2 or 3 of appendix B of this part.
(10)If a CEMS is used, results of daily CEMS drift tests and quarterly accuracy assessments as required under appendix F, Procedure 1 of this part.
(11)If fuel supplier certification is used to demonstrate compliance, records of fuel supplier certification is used to demonstrate compliance, records of fuel supplier certification as described under paragraph (f)(1), (2), (3), or
(4)of this section, as applicable. In addition to records of fuel supplier certifications, the report shall include a certified statement signed by the owner or operator of the affected facility that the records of fuel supplier certifications submitted represent all of the fuel combusted during the reporting period.
(f)Fuel supplier certification shall include the following information:
(1)For distillate oil:
(i)The name of the oil supplier;
(ii)A statement from the oil supplier that the oil complies with the specifications under the definition of distillate oil in § 60.41c; and
(iii)The sulfur content of the oil.
(2)For residual oil:
(i)The name of the oil supplier;
(ii)The location of the oil when the sample was drawn for analysis to determine the sulfur content of the oil, specifically including whether the oil was sampled as delivered to the affected facility, or whether the sample was drawn from oil in storage at the oil supplier's or oil refiner's facility, or other location;
(iii)The sulfur content of the oil from which the shipment came (or of the shipment itself); and
(iv)The method used to determine the sulfur content of the oil.
(3)For coal:
(i)The name of the coal supplier;
(ii)The location of the coal when the sample was collected for analysis to determine the properties of the coal, specifically including whether the coal was sampled as delivered to the affected facility or whether the sample was collected from coal in storage at the mine, at a coal preparation plant, at a coal supplier's facility, or at another location. The certification shall include the name of the coal mine (and coal seam), coal storage facility, or coal preparation plant (where the sample was collected);
(iii)The results of the analysis of the coal from which the shipment came (or of the shipment itself) including the sulfur content, moisture content, ash content, and heat content; and
(iv)The methods used to determine the properties of the coal.
(4)For other fuels:
(i)The name of the supplier of the fuel;
(ii)The potential sulfur emissions rate of the fuel in ng/J heat input; and
(iii)The method used to determine the potential sulfur emissions rate of the fuel. (g)(1) Except as provided under paragraphs (g)(2) and (g)(3) of this section, the owner or operator of each affected facility shall record and maintain records of the amount of each fuel combusted during each operating day.
(2)As an alternative to meeting the requirements of paragraph (g)(1) of this section, the owner or operator of an affected facility that combusts only natural gas, wood, fuels using fuel certification in § 60.48c(f) to demonstrate compliance with the SO <sup>2</sup> standard, fuels not subject to an emissions standard (excluding opacity), or a mixture of these fuels may elect to record and maintain records of the amount of each fuel combusted during each calendar month.
(3)As an alternative to meeting the requirements of paragraph (g)(1) of this section, the owner or operator of an affected facility or multiple affected facilities located on a contiguous property unit where the only fuels combusted in any steam generating unit (including steam generating units not subject to this subpart) at that property are natural gas, wood, distillate oil meeting the most current requirements in § 60.42C to use fuel certification to demonstrate compliance with the SO <sup>2</sup> standard, and/or fuels, excluding coal and residual oil, not subject to an emissions standard (excluding opacity) may elect to record and maintain records of the total amount of each steam generating unit fuel delivered to that property during each calendar month.
(h)The owner or operator of each affected facility subject to a federally enforceable requirement limiting the annual capacity factor for any fuel or mixture of fuels under § 60.42c or § 60.43c shall calculate the annual capacity factor individually for each fuel combusted. The annual capacity factor is determined on a 12-month rolling average basis with a new annual capacity factor calculated at the end of the calendar month.
(i)All records required under this section shall be maintained by the owner or operator of the affected facility for a period of two years following the date of such record.
(j)The reporting period for the reports required under this subpart is each six-month period. All reports shall be submitted to the Administrator and shall be postmarked by the 30th day following the end of the reporting period. Appendix B—[Amended] 7. Appendix B to part 60 is amended by revising section 8.3.1 in Performance Specification 2, to read as follows: Appendix B to Part 60—Performance Specifications Performance Specification 2—Specifications and Test Procedures for SO <sup>2</sup> and NO <sup>X</sup> Continuous Emission Monitoring Systems in Stationary Sources 8.3.1 *CD Test Period.* While the affected facility is operating, determine the magnitude of the CD once each day (at 24-hour intervals) for 7 consecutive calendar days according to the procedure given in Sections 8.3.2 through 8.3.4. Alternatively, the CD test may be conducted over 7 consecutive unit operating days. Appendix F—[Amended] 8. Procedure 1 in Appendix F to part 60 is amended by: a. Revising the first sentence of section 5.1.1; and b. Revising section 5.1.4. The revisions read as follows: Appendix F to Part 60—Quality Assurance Procedures 5.1.1 Relative Accuracy Test Audit (RATA). The RATA must be conducted at least once every four calendar quarters, except as otherwise noted in section 5.1.4 of this appendix. 5.1.4 Other Alternative Audits. Other alternative audit procedures may be used as approved by the Administrator for three of four calendar quarters. One RATA is required at least every four calendar quarters, except in the case where the affected facility is off-line (does not operate) in the fourth calendar quarter since the quarter of the previous RATA. In that case, the RATA shall be performed in the quarter in which the unit recommences operation. Also, cylinder gas audits are not be required for calendar quarters in which the affected facility does not operate. [FR Doc. E7-7673 Filed 6-12-07; 8:45 am] BILLING CODE 6560-50-P 72 113 Wednesday, June 13, 2007 Presidential Documents Part III The President Proclamation 8156—Father's Day, 2007 Title 3— The President Proclamation 8156 of June 11, 2007 Father's Day, 2007 By the President of the United States of America A Proclamation On Father's Day, we reflect on the many ways that fathers contribute to the lives of their children with spoken words and unspoken kindness. Fathers are one of the most important influences in the lives of children, and their unconditional love is an indispensable anchor of certainty and strength. By placing their family's well-being above their own, fathers provide children with an example of what it means to be a responsible person. Through unwavering devotion and daily sacrifice, fathers work to create an environment where children are protected and encouraged. Fathers instill in their children an understanding of right and wrong and help them to grow in confidence and character. These dedicated men strive to give their sons and daughters the necessary foundation to make good choices and lead lives of purpose. On Father's Day and throughout the year, we honor the men who have taken on the great joy and responsibility of fatherhood, and we celebrate their extraordinary impact and influence. All Americans are especially grateful to the many fathers who are serving their country as members of the Armed Forces, and we lift them and their loved ones up in prayer. NOW, THEREFORE, I, GEORGE W. BUSH, President of the United States of America, in accordance with a joint resolution of the Congress approved April 24, 1972, as amended (36 U.S.C. 109), do hereby proclaim June 17, 2007, as Father's Day. I encourage all Americans to express admiration and appreciation to fathers for their many contributions to our Nation's children. I direct the appropriate officials of the Government to display the flag of the United States on all Government buildings on this day. I also call upon State and local governments and citizens to observe this day with appropriate programs, ceremonies, and activities. IN WITNESS WHEREOF, I have hereunto set my hand this eleventh day of June, in the year of our Lord two thousand seven, and of the Independence of the United States of America the two hundred and thirty-first. GWBOLD.EPS [FR Doc. 07-2948 Filed 6-12-07; 8:47 am]
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  • 17 CFR 240.19
  • 5 USC 78s(b)(2)
  • Pub. L. 104-13
  • 20 CFR 404.917-404
  • 20 CFR 404.801-404
  • 20 CFR 404.1601-1661
  • 20 CFR 405.427
  • 79 Stat. 985
  • 49 CFR 391.41(b)(10)
  • 49 CFR 391.64(b)
  • 49 CFR 391.41
  • 49 CFR 381
  • 49 CFR 663
  • T.D. 8124
  • T.D. 8686
  • 40 CFR 60
  • 40 CFR 9
  • Pub. L. 104-4
  • Pub. L. 104-113
  • 40 CFR 51.18
  • 40 CFR 70.2
  • 40 CFR 72.2
  • 40 CFR 261
  • 40 CFR 761
  • 40 CFR 761.70
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U.S.C.§ 78s
U.S.C.§ 78f
U.S.C.§ 78c
U.S.C.§ 78k
C.F.R.§ 200.30-3
U.S.C.§ 552
Cite17 CFR 240.19
Cite5 USC 78s(b)(2)
Pub. L.Pub. L. 104-13
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