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National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units; Correction

Document Details

Information about this document as published in the Federal Register.

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ACTION:

Final rule; correction.

SUMMARY:

This document corrects certain preamble and regulatory text. This action corrects typographical errors, such as cross-reference errors and certain preamble text that is not consistent with the final regulatory text, which published in the Federal Register on Thursday, February 16, 2012 (77 FR 9304).

DATES:

Effective date: April 19, 2012.

FOR FURTHER INFORMATION CONTACT:

For the NESHAP action: Mr. William Maxwell, Energy Strategies Group, Sector Policies and Programs Division, (D243-01), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; Telephone number: (919) 541-5430; Fax number (919) 541-5450; email address: maxwell.bill@epa.gov. For the new source performance standard (NSPS) action: Mr. Christian Fellner, Energy Strategies Group, Sector Policies and Programs Division, (D243-01), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; Telephone number: (919) 541-4003; Fax number (919) 541-5450; email address: fellner.christian@epa.gov.

SUPPLEMENTARY INFORMATION:

This document corrects certain preamble and regulatory text. It is proper to issue this final rule correction without notice and comment. Section 553 of the Administrative Procedure Act (APA), 5 U.S.C. 553(b)(B), provides that, when an agency for good cause finds that notice and public procedure are impracticable, unnecessary, or contrary to the public interest, the agency may issue a rule without providing notice and an opportunity for public comment. We have determined that there is good cause for making this action final without prior proposal and opportunity for comment because the changes to the rule are minor technical corrections, are noncontroversial, and do not substantively change the agency actions taken in the final rule. Notice and comment is unnecessary, because these changes do not affect the rights or obligations of outside parties, and do not alter the substantive requirements of the code of federal regulations (CFR), except to the extent that one regulatory provision included an inadvertent typographical error that EPA must amend to align with the plain text of the Clean Air Act (CAA). We find that this constitutes good cause under 5 U.S.C. 553(b)(B).The corrections can be categorized generally as follows: Correction of typographical errors (e.g., cross-reference errors) and correction of certain preamble text that does not conform to the final regulatory text. Below, we identify each technical correction to the preamble and regulatory text.

1. Table 5 on page 9368 is corrected to read as follows:

Table 5—Alternate Emission Limitations for Existing Coal- and Oil-Fired EGUS

Subcategory/pollutantCoal-fired EGUsIGCCLiquid oil, continentalLiquid oil, non-continentalSolid oil-derived
SO22.0E-1 lb/MMBtu (1.5E0 lb/MWh)NANANA3.0E-1 lb/MMBtu (2.0E0 lb/MWh).
Total non-mercury metals5.0E-5 lb/MMBtu (5.0E-1 lb/GWh)6.0E-5 lb/MMBtu (5.0E-1 lb/GWh)8.0E-4 lb/MMBtu (8.0E-3 lb/MWh) a6.0E-4 lb/MMBtu(7.0E-3 lb/MWh) a4.0E-5 lb/MMBtu (6.0E-1 lb/GWh).
Antimony, Sb8.0E-1 lb/TBtu (8.0E-3 lb/GWh)1.4E0 lb/TBtu (2.0E-2 lb/GWh)1.3E+1 lb/TBtu (2.0E-1 lb/GWh)2.2E0 lb/TBtu (2.0E-2 lb/GWh)8.0E-1 lb/TBtu (7.0E-3 lb/GWh).
Arsenic, As1.1E0 lb/TBtu (2.0E-2 lb/GWh)1.5E0 lb/TBtu (2.0E-2 lb/GWh)2.8E0 lb/TBtu (3.0E-2 lb/GWh)4.3E0 lb/TBtu (8.0E-2 lb/GWh)3.0E-1 lb/TBtu (5.0E-3 lb/GWh).
Beryllium, Be2.0E-1 lb/TBtu (2.0E-3 lb/GWh)1.0E-1 lb/TBtu (1.0E-3 lb/GWh)2.0E-1 lb/TBtu (2.0E-3 lb/GWh)6.0E-1 lb/TBtu (3.0E-3 lb/GWh)6.0E-2 lb/TBtu (5.0E-4 lb/GWh).
Cadmium, Cd3.0E-1 lb/TBtu (3.0E-3 lb/GWh)1.5E-1 lb/TBtu (2.0E-3 lb/GWh)3.0E-1 lb/TBtu 2.0E-3 lb/GWh)3.0E-1 lb/TBtu (3.0E-3 lb/GWh)3.0E-1 lb/TBtu (4.0E-3 lb/GWh).
Chromium, Cr2.8E0 lb/TBtu (3.0E-2 lb/GWh)2.9E0 lb/TBtu (3.0E-2 lb/GWh)5.5E0 lb/TBtu (6.0E-2 lb/GWh)3.1E+1 lb/TBtu (3.0E-1 lb/GWh)8.0E-1 lb/TBtu (2.0E-2 lb/GWh).
Cobalt, Co8.0E-1 lb/TBtu (8.0E-3 lb/GWh)1.2E0 lb/TBtu (2.0E-2 lb/GWh)2.1E+1 lb/TBtu (3.0E-1 lb/GWh)1.1E+2 lb/TBtu (1.4E0 lb/GWh)1.1E0 lb/TBtu (2.0E-2 lb/GWh).
Lead, Pb1.2E0 lb/TBtu (2.0E-2 lb/GWh)1.9E+2 lb/TBtu (1.8E0 lb/GWh)8.1E0 lb/TBtu (8.0E-2 lb/GWh)4.9E0 lb/TBtu (8.0E-2 lb/GWh)8.0E-1 lb/TBtu (2.0E-2 lb/GWh).
Manganese, Mn4.0E0 lb/TBtu (5.0E-2 lb/GWh2.5E0 lb/TBtu (3.0E-2 lb/GWh)2.2E+1 lb/TBtu (3.0E-1 lb/GWh)2.0E+1 lb/TBtu (3.0E-1 lb/GWh)2.3E0 lb/TBtu (4.0E-2 lb/GWh).
Mercury, HgNANA2.0E-1 lb/TBtu (2.0E-3 lb/GWh)4.0E-2 lb/TBtu (4.0E-4 lb/GWh)NA.
Nickel, Ni3.5E0 lb/TBtu (4.0E-2 lb/GWh)6.5E0 lb/TBtu (7.0E-2 lb/GWh)1.1E+2 lb/TBtu (1.1E0 lb/GWh)4.7E+2 lb/TBtu (4.1E0 lb/GWh)9.0E0 lb/TBtu (2.0E-1 lb/GWh).
Selenium, Se5.0E0 lb/TBtu (6.0E-2 lb/GWh)2.2E+1 lb/TBtu (3.0E-1 lb/GWh)3.3E0 lb/TBtu (4.0E-2 lb/GWh)9.8E0 lb/TBtu (2.0E-1 lb/GWh)1.2E0 lb/TBtu (2.0E-2 lb/GWh).
NA = Not applicable.
a Includes Hg.

The output-format values for the antimony and beryllium emission limits for existing solid oil-derived fuel-fired units were incorrect as published in the preamble to the final rule (i.e., the incorrect “8.0E-3 lb/GWh” instead of the correct “7.0E-3 lb/GWh” for antimony and the incorrect “6.0E-4 lb/GWh” instead of the correct “5.0E-4 lb/GWh” for beryllium). In addition, the format of the input- and output-based lead emissions limits for existing IGCC EGUs was incorrect as published in the preamble to the final rule (i.e., the incorrect “1.9E+2 lb/MMBtu or 1.8E0 lb/MWh” instead of the correct “1.9E+2 lb/TBtu or 1.8E0 lb/GWh”). In each case, the correct values are indicated in the spreadsheets found in docket entry EPA-HQ-OAR-2009-0234-20132 and the published values were transcription errors. This same correction is made to the regulatory text later in this document.

2. On page 9401, column 1, first full paragraph, the fourth sentence is corrected to read as follows: “This subcategory applies only to oil-fired EGUs that act as peaking units, as they generally address reliability issues.”

We are revising this sentence because the original sentence in the preamble to the final rule stated: “This subcategory applies only to oil-fired EGUs that operate on oil alone and act as peaking units, as they generally address reliability issues.” (emphasis added). The italicized language is not consistent with the regulatory definition of “oil-fired EGU” or the definition of “limited-use liquid oil-fired subcategory” because it incorrectly indicates that the subcategory applies only to oil-fired EGUs that operate on oil alone. See 40 CFR 63.10042.

3. The definition of “Boiler operating day” in § 60.41Da Definitions, the date “February 29, 2005” is corrected to read “March 1, 2005” because there was no February 29 in 2005.

4. Section 60.49Da(a)(4)(i) is revised to correct the typographical error related to the incorrect cross reference to section 60.51a(d) which does not exist. The correct cross reference is to section 60.51Da(d).

5. Sections 63.9982(a)(1) and (a)(2) are revised to include the “§” symbol which was inadvertently left off of the references to section 63.10042 (i.e., “63.10042” vs. the correct “§ 63.10042”.

6. Section 63.9982(d) is revised to correct the typographical error which left out the word “in” from the phrase “* * * change in process * * *”

7. Section 63.9985(a)(2) is revised to remove the words “or modification.” We erroneously included this language in the final rule definition of a new source for purposes of the NESHAP. The language included in the final rule comes from the CAA section 111 statutory definition for “new source,” instead of the CAA section 112 definition of “new source.” CAA section 112 does not include “modified” sources in the definition of new sources, and, thus, the inclusion of such sources in the definition was an inadvertent drafting error.

8. Section 63.9991(c) is revised to remove the term “coal-fired” from the phrase “coal-fired EGU.” This section expressly references Tables 1 and 2 of this subpart and those tables include alterative sulfur dioxide (SO2) limits for all EGUs meeting the requirements of section 63.9991(c), not just coal-fired EGUs. Thus, the provision as written in the final rule was incorrectly limited to coal-fired EGUs.

9. Section 63.10000(c)(1) is revised to include integrated gasification combined cycle (IGCC) EGUs among the subcategories listed. Section 63.10000(c) addresses initial performance testing. IGCC EGUs are included in the requirements of section 63.10000(c)(1)(i) (which deals with initial performance testing for purposes of determining low emitting EGU (LEE) status) and, thus, the omission of IGCC EGUs from the introductory language in section 63.10000(c)(1) was an inadvertent error.

10. Section 63.10000(c)(1)(i)(B) is revised to correct a typographical error (“* * * solid oil-derived fuel-fired * * *” rather than the incorrect “* * * solid oil-fired fuel-fired * * *”).

11. Section 63.10000(c)(2)(iv) is revised to correct a typographical error and include “you” in the phrase “* * * but you must * * *”

12. Section 63.10000(d)(5)(i) is revised to correct the typographical error of including the incorrect term “CEMS” rather than the correct term “CMS.” The text of sections 63.10000(d)(2)(i), (3), and (4) all refer to the broader “CMS” (which includes both continuous parameter monitoring system (CPMS) and continuous emission monitoring system (CEMS)). Thus, use of the narrower CEMS in section 63.10000(d)(5)(i) was an inadvertent error. Further, the term “CPMS” in the last sentence of the section is corrected to read “PM CPMS” consistent with section 63.10010(h), which section is referenced in section 63.10000(d)(5)(i) and specifically addresses PM CPMS.

13. Section 63.10000(d)(5)(iv) is revised to use language consistent with section 63.8(d) (changing “ongoing data quality assurance procedures” to “quality control program”), as section 63.8 is cited in this section. The title of section 63.8(d) is “quality control program” and the phrase “ongoing data quality assurance procedures” does not appear in that provision.

14. Section 63.10000(f) is revised to correct a typographical error by replacing “distributions system” with the correct “distribution system.”

15. Section 63.10005(b)(2) is revised to correct a typographical error by changing “* * * valid data CMS data * * *” to “valid CMS data”.

16. Section 63.10005(d)(1) is revised to correct a typographical error (the correct “* * * Table 1 or 2 to this * * *” rather than the incorrect “* * * Table 1 or 2 of this * * *” in two places).

17. Section 63.10005(d)(4)(ii) is revised to correct the typographical error associated with the use of “corresponding” rather than the correct word “corresponds.”

18. Sections 63.10005(h)(3)(iii)(C)(1) and (2) are revised to correct the typographical errors associated with the conversion factors from million British thermal units per hour (MMBtu/hr) to trillion Btu/hr (TBtu/hr) (i.e., the correct 10−6 rather than the incorrect 106) and from megawatts (MW) to gigawatts (GW) (i.e., the correct 10−3 rather than the incorrect 103). The exponents as published are technically incorrect and the conversions would not work as published.

19. Section 63.10006(a) is revised to correct a typographical error. Specifically, we inadvertently omitted the word “fired” from the phrase “* * * solid oil-derived fuel- and * * *” The phrase should read “* * * solid oil-derived fuel-fired and * * *”

20. Section 63.10007(c) is revised to correct the typographical error associated with the incorrect cross reference to the non-existent section 63.10011(b)(5). The correct cross reference is to section 63.10011(b).

21. Section 63.10009(g) is revised to correct the typographical error related to the incorrect cross reference to sections 63.10009(f)(1) through (3). Section 63.10009(g) deals with determining weighted average emission rates, but section 63.10009(f) deals with demonstrating eligibility for an emissions averaging group and is, thus, an incorrect cross reference. The correct cross reference is to sections 63.10009(g)(1) through (2), which sections provide specific direction on the manner in which sources establish weighted average emission rates.

22. Section 63.10009(j)(2)(i)(A) is revised to correct the typographical error related to the incorrect cross reference to section 63.10009(h)(1), which does not exist. The correct cross reference is to section 63.10009(j)(1).

23. Sections 63.10010(a)(6)(iii) and (iv) are revised to correct the typographical errors related to the incorrect cross references to sections 63.10010(a)(5)(iii)(B) and (a)(5)(iii)(C), which do not exist. The correct cross references are to sections 63.10010(a)(6)(ii) and (iii), respectively.

24. Sections 63.10010(g), 63.10011(c)(1), 63.10021(b), and 63.10022(a)(1) are revised to correct the inadvertent omission of the alternate 90-day averaging period. The provisions as included in the final rule only referred to the 30-day averaging periods that are generally utilized for determining compliance with the final standards; however, as indicated in section 63.10009(a)(2), sources are also authorized to use the alternate 90-day averaging period for certain standards when emissions averaging is employed at a facility.

25. Section 63.10020(d) is revised to correct a typographical error by replacing “of” with “from” in the phrase “* * * deviation from the * * *”

26. Section 63.10030(e)(7)(i) is revised to correct the typographical error related to the incorrect cross reference to section 63.10006(i). Section 63.10006(i) addresses the tune-up requirement, but section 63.10030(e)(7)(i) concerns LEE requirements, not tune-up requirements. The correct cross reference is to section 63.10006(b), which addresses the reduced performance (i.e., stack) testing for LEE, which allows a source to test every 3 years as discussed in section 63.10030(e)(7)(i).

27. Section 63.10031(c)(4) is revised to correct an incorrect statement. The final rule does not require annual inspections; thus, the “annual” has been replaced with “every 36 (or 48) months” to be consistent with other rule text.

28. The definitions of “Non-mercury (Hg) HAP metals” and “Oil” in section 63.10042 are revised to correct the typographical error that did not separate the two definitions in the published rule.

29. Table 2 to Subpart UUUUU of Part 63 is revised to correct the typographical errors related to the lack of a superscript for footnotes (“2”) denoting “gross electric output” for filterable particulate matter emissions from “2. Coal-fired unit low rank virgin coal,” “3. IGCC,” “4. Liquid oil-fired unit—continental (excluding limited-use liquid oil-fired subcategory units),” “Liquid oil-fired unit—non-continental (excluding limited-use liquid oil-fired subcategory units),” and “6. Solid oil-derived fuel-fired unit.”

In addition, the format of the input- and output-based lead emissions limits for “3. IGCC unit” was incorrect as published (i.e., the incorrect “1.9E+2 lb/MMBtu or 1.8E0 lb/MWh” instead of the correct “1.9E+2 lb/TBtu or 1.8E0 lb/GWh”). Further, the output-format values for the antimony and beryllium emission limits for “6. Solid oil-derived fuel-fired unit” were incorrect as published (i.e., the incorrect “8.0E-3 lb/GWh” instead of the correct “7.0E-3 lb/GWh” for antimony and the incorrect “6.0E-4 lb/GWh” instead of the correct “5.0E-4 lb/GWh” for beryllium). In each case, the correct values are indicated in the spreadsheets found in docket entry EPA-HQ-OAR-2009-0234-20132 and the published values are transcription errors.

30. For the reasons described in Paragraph 24 above, Table 7 to Subpart UUUUU of Part 63 is revised to address the inadvertent omission of the alternate 90-day averaging period that is available.

31. For the reasons described in Paragraph 24 above, Paragraphs 6.2.1.4 and 6.2.2.3 to Appendix A to Subpart UUUUU of Part 63 are revised to address the inadvertent omission of the alternate 90-day averaging period that is available.

32. Paragraph 7.2.4 to Appendix A to Subpart UUUUU of Part 63 is revised to correct the typographical error related to the incorrect cross reference to paragraphs 7.1.10.1 through 7.1.10.7; these paragraphs do not exist, however. The correct cross reference is paragraphs 7.1.9.1 through 7.1.9.7.

33. Paragraph 7.2.5.3.4 to Appendix A to Subpart UUUUU of Part 63 is revised to correct the typographical error related to the incorrect cross reference to paragraph 7.1.90.1; this paragraph does not exist, however. The correct cross reference is paragraph 7.1.9.1.

Statutory and Executive Order Reviews

Under Executive Order (EO) 12866, Regulatory Planning and Review (58 FR 51735, October 4, 1993), this action is not a “significant regulatory action” and is therefore not subject to review by the Office of Management and Budget (OMB). This action is not a “major rule” as defined by 5 U.S.C. 804(2). The technical corrections do not impose an information collection burden under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.).

Because EPA has made a “good cause” finding that this action is not subject to notice and comment requirements under the APA or any other statute, it is not subject to the regulatory flexibility provisions of the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), or to sections 202 and 205 of the Unfunded Mandates Reform Act of 1995 (UMRA) (Pub. L. 104-4). In addition, this action does not significantly or uniquely affect small governments or impose a significant intergovernmental mandate, as described in sections 203 and 204 of the UMRA.

The corrections do not have substantial direct effects on the states, or 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 EO 13132, Federalism (64 FR 43255, August 10, 1999).

This action also does not significantly or uniquely affect the communities of tribal governments, as specified by EO 13175, Consultation and Coordination with Indian Tribal Governments (65 FR 67249, November 9, 2000). The technical corrections also are not subject to EO 13045, Protection of Children from Environmental Health and Safety Risks (62 FR 19885, April 23, 1997) because this action is not economically significant.

The corrections are not subject to EO 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use (66 FR 28355, May 22, 2001) because this action is not a significant regulatory action under EO 12866.

The corrections do not involve changes to the technical standards related to test methods or monitoring methods; thus, the requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272) do not apply.

The corrections also do not involve special consideration of environmental justice-related issues as required by EO 12898, Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations (59 FR 7629, February 16, 1994).

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the U.S. The EPA submitted a report containing the final action and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the U.S. This action is not a “major rule” as defined by 5 U.S.C. 804(2). The final rule will be effective on April 16, 2012.

The EPA's compliance with the above statutes and EOs for the underlying rule is discussed in the February 16, 2012, Federal Register document containing “National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units.”

List of Subjects

Dated: March 27, 2012.

Lisa P. Jackson,

Administrator.

Accordingly, title 40, chapter I, of the Code of the Federal Regulations is amended by making the following correcting amendments:

PART 60—[AMENDED]

1. The authority citation for part 60 continues to read as follows:

Authority: 42 U.S.C. 7401 et seq.

2. In § 60.41Da, revise the definition of “Boiler operating day” to read as follows:

Definitions.
* * * * *

Boiler operating day for units constructed, reconstructed, or modified before March 1, 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.

* * * * *

3. Revise § 60.49Da(a)(4)(i) to read as follows:

Emission monitoring.

(a) * * *

(4) * * *

(i) The affected facility combusts only gaseous fuels and/or liquid fuels (excluding residue oil) with a potential SO2 emissions rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit operates according to a written site-specific monitoring plan approved by the 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. For testing performed as part of this site-specific monitoring plan, the permitting authority may require as an alternative to the notification and reporting requirements specified in §§ 60.8 and 60.11 that the owner or operator submit any deviations with the excess emissions report required under § 60.51Da(d).

* * * * *

PART 63—[AMENDED]

4. The authority citation for

Authority: 42 U.S.C. 7401, et seq.

5. Revise § 63.9982(a)(1), (a)(2), and (d) to read as follows:

What is the affected source of this subpart?

(a) * * *

(1) The affected source of this subpart is the collection of all existing coal- or oil-fired EGUs, as defined in § 63.10042, within a subcategory.

(2) The affected source of this subpart is each new or reconstructed coal- or oil-fired EGU as defined in § 63.10042.

* * * * *

(d) An EGU is existing if it is not new or reconstructed. An existing electric steam generating unit that meets the applicability requirements after the effective date of this final rule due to a change in process (e.g., fuel or utilization) is considered to be an existing source under this subpart.

* * * * *

6. Revise § 63.9985(a)(2) to read as follows:

What is a new EGU?

(a) * * *

(2) An EGU that commenced reconstruction after May 3, 2011.

* * * * *

7. In § 63.9991, revise paragraph(c) introductory text to read as follows:

What emission limitations, work practice standards, and operating limits must I meet?
* * * * *

(c) You may use the alternate SO2 limit in Tables 1 and 2 to this subpart only if your EGU:

* * * * *

8. In § 63.10000, revise paragraphs(c)(1) introductory text, (c)(1)(i)(B), (c)(2)(iv), (d)(5)(i), (d)(5)(iv) and (f) to read as follows:

What are my general requirements for complying with this subpart?
* * * * *

(c)(1) For coal-fired units, IGCC units, and solid oil-derived fuel-fired units, initial performance testing is required for all pollutants, to demonstrate compliance with the applicable emission limits.

(i) * * *

(B) You may not pursue the LEE option for Hg if your coal-fired, solid oil-derived fuel-fired EGU or IGCC EGU is new.

* * * * *

(2) * * *

(iv) If your unit qualifies as a limited-use liquid oil-fired as defined in § 63.10042, then you are not subject to the emission limits in Tables 1 and 2, but you must comply with the performance tune-up work practice requirements in Table 3.

* * * * *

(d) * * *

(5) * * *

(i) Installation of the CMS or sorbent trap monitoring system sampling probe or other interface at a measurement location relative to each affected process unit such that the measurement is representative of control of the exhaust emissions (e.g., on or downstream of the last control device). See § 63.10010(a) for further details. For PM CPMS installations, follow the procedures in § 63.10010(h).

* * * * *

(iv) Performance evaluation procedures and acceptance criteria (e.g., calibrations), including the quality control program in accordance with the general requirements of § 63.8(d).

* * * * *

(f) You are subject to the requirements of this subpart for at least 6 months following the last date you met the definition of an EGU subject to this subpart (e.g., 6 months after a cogeneration unit provided more than one third of its potential electrical output capacity and more than 25 megawatts electrical output to any power distribution system for sale). You may opt to remain subject to the provisions of this subpart beyond 6 months after the last date you met the definition of an EGU subject to this subpart, unless you are a solid waste incineration unit subject to standards under CAA section 129 (e.g., 40 CFR Part 60, Subpart CCCC (New Source Performance Standards (NSPS) for Commercial and Industrial Solid Waste Incineration Units, or Subpart DDDD (Emissions Guidelines (EG) for Existing Commercial and Industrial Solid Waste Incineration Units). Notwithstanding the provisions of this subpart, an EGU that starts combusting solid waste is immediately subject to standards under CAA section 129 and the EGU remains subject to those standards until the EGU no longer meets the definition of a solid waste incineration unit consistent with the provisions of the applicable CAA section 129 standards.

* * * * *

9. Revise § 63.10005(b)(2), (d)(1), (d)(4)(ii), and (h)(3)(iii)(C)(

What are my initial compliance requirements and by what date must I conduct them?
* * * * *

(b) * * *

(2) For a performance test based on data from a certified CEMS or sorbent trap monitoring system, the test consists of all valid CMS data recorded in the 30 boiler operating days immediately preceding that date;

* * * * *

(d) * * *

(1) For an affected coal-fired, solid oil-derived fuel-fired, or liquid oil-fired EGU, you may demonstrate initial compliance with the applicable SO2, HCl, or HF emissions limit in Table 1 or 2 to this subpart through use of an SO2, HCl, or HF CEMS installed and operated in accordance with Part 75 of this chapter or Appendix B to this subpart, as applicable. You may also demonstrate compliance with a filterable PM emission limit in Table 1 or 2 to this subpart through use of a PM CEMS installed, certified, and operated in accordance with § 63.10010(i). Initial compliance is achieved if the arithmetic average of 30-boiler operating days of quality-assured CEMS data, expressed in units of the standard (see § 63.10007(e)), meets the applicable SO2, PM, HCl, or HF emissions limit in Table 1 or 2 to this subpart. Use Equation 19-19 of Method 19 in appendix A-7 to Part 60 of this chapter to calculate the 30-boiler operating day average emissions rate. (Note: For this calculation, the term Ehj in Equation 19-19 must be in the same units of measure as the applicable HCl or HF emission limit in Table 1 or 2 to this subpart).

* * * * *

(4) * * *

(i) * * *

(ii) You must demonstrate continuous compliance with the CMS site-specific operating limit that corresponds to the results of the performance test demonstrating compliance with the HCl or HF emissions limit.

* * * * *

(h) * * *

(3) * * *

(iii) * * *

(C) * * *

(1) Multiply the average lb/TBtu Hg emission rate (determined according to paragraph (h)(3)(iii)(A) of this section) by the maximum potential annual heat input to the unit (TBtu), which is equal to the maximum rated unit heat input (TBtu/hr) times 8,760 hours. If the maximum rated heat input value is expressed in units of MMBtu/hr, multiply it by 10 −6 to convert it to TBtu/hr; or

(2) Multiply the average lb/GWh Hg emission rate (determined according to paragraph (h)(3)(iii)(B) of this section) by the maximum potential annual electricity generation (GWh), which is equal to the maximum rated electrical output of the unit (GW) times 8,760 hours. If the maximum rated electrical output value is expressed in units of MW, multiply it by 10 −3 to convert it to GW; or

* * * * *

10. Revise § 63.10006(a) to read as follows:

When must I conduct subsequent performance tests or tune-ups?

(a) For liquid oil-fired, solid oil-derived fuel-fired and coal-fired EGUs and IGCC units using PM CPMS to monitor continuous performance with an applicable emission limit as provided for under § 63.10000(c), you must conduct all applicable performance tests according to Table 5 to this subpart and § 63.10007 at least every year.

* * * * *

11. Revise § 63.10007(c) to read as follows:

What methods and other procedures must I use for the performance tests?
* * * * *

(c) If you choose to comply with the filterable PM emission limit and demonstrate continuous performance using a PM CPMS for an applicable emission limit as provided for in § 63.10000(c), you must also establish an operating limit according to § 63.10011(b) and Tables 4 and 6 to this subpart. Should you desire to have operating limits that correspond to loads other than maximum normal operating load, you must conduct testing at those other loads to determine the additional operating limits.

* * * * *

12. In § 63.10009, revise paragraphs (g) introductory text and (j)(2)(i)(A) to read as follows:

May I use emissions averaging to comply with this subpart?
* * * * *

(g) You must determine the weighted average emissions rate in units of the applicable emissions limit on a 30 day rolling average (90 day rolling average for Hg) basis according to paragraphs (g)(1) through (2) of this section. The first averaging period begins on 30 (or 90 for Hg) days after February 16, 2015 or the date that you begin emissions averaging, whichever is earlier.

* * * * *

(j) * * *

(2) * * *

(i) * * *

(A) Whether the content of the plan includes all of the information specified in paragraph (j)(1) of this section; and

* * * * *

13. In § 63.10010, revise paragraphs (a)(6)(iii), (a)(6)(iv) and (g) to read as follows:

What are my monitoring, installation, operation, and maintenance requirements?

(a) * * *

(6) * * *

(iii) Sum the products determined under paragraph (a)(6)(ii) of this section; and

(iv) Divide the result obtained in paragraph (a)(6)(iii) of this section by the total hourly stack gas flow rate for the unit, summed across all of the stacks or ducts.

* * * * *

(g) If you use a Hg CEMS or a sorbent trap monitoring system, you must install, certify, operate, maintain and quality-assure the data from the monitoring system in accordance with appendix A to this subpart. You must calculate and record a 30- (or, if alternate emissions averaging is used, 90-) boiler operating day rolling average Hg emission rate, in units of the standard, updated after each new boiler operating day. Each 30- (or, if alternate emissions averaging is used, 90-) boiler operating day rolling average emission rate, calculated according to section 6.2 of appendix A to the subpart, is the average of all of the valid hourly Hg emission rates in the preceding 30- (or, if alternate emissions averaging is used, a 90-) boiler operating days. Section 7.1.4.3 of appendix A to this subpart explains how to reduce sorbent trap monitoring system data to an hourly basis.

* * * * *

14. Revise § 63.10011(c)(1) to read as follows:

How do I demonstrate initial compliance with the emissions limits and work practice standards?
* * * * *

(c)(1) If you use CEMS or sorbent trap monitoring systems to measure a HAP (e.g., Hg or HCl) directly, the first 30-boiler operating day (or, if alternate emissions averaging is used for Hg, the 90-boiler operating day) rolling average emission rate obtained with certified CEMS after the applicable date in § 63.9984 (or, if applicable, prior to that date, as described in § 63.10005(b)(2)), expressed in units of the standard, is the initial performance test. Initial compliance is demonstrated if the results of the performance test meet the applicable emission limit in Table 1 or 2 to this subpart.

* * * * *

15. Revise § 63.10020(d) to read as follows:

How do I monitor and collect data to demonstrate continuous compliance?
* * * * *

(d) Except for periods of monitoring system malfunctions or monitoring system out-of-control periods, repairs associated with monitoring system malfunctions or monitoring system out-of-control periods, and required monitoring system quality assurance or quality control activities including, as applicable, calibration checks and required zero and span adjustments), failure to collect required data is a deviation from the monitoring requirements.

* * * * *

16. Revise § 63.10021(b) to read as follows:

How do I demonstrate continuous compliance with the emission limitations, operating limits, and work practice standards?
* * * * *

(b) Except as otherwise provided in § 63.10020(c), if you use a CEMS to measure SO2, PM, HCl, HF, or Hg emissions, or using a sorbent trap monitoring system to measure Hg emissions, you must demonstrate continuous compliance by using all quality-assured hourly data recorded by the CEMS (or sorbent trap monitoring system) and the other required monitoring systems (e.g., flow rate, CO2, O2, or moisture systems) to calculate the arithmetic average emissions rate in units of the standard on a continuous 30-boiler operating day (or, if alternate emissions averaging is used for Hg, 90-boiler operating day) rolling average basis, updated at the end of each new boiler operating day. Use Equation 8 to determine the 30- (or, if applicable, 90-) boiler operating day rolling average.

Where:

Heri is the hourly emissions rate for hour i and n is the number of hourly emissions rate values collected over 30- (or, if applicable, 90-) boiler operating days.

* * * * *

17. Revise § 63.10022(a)(1) to read as follows:

How do I demonstrate continuous compliance under the emissions averaging provision?

(a) * * *

(1) For each 30- (or 90-) day rolling average period, demonstrate compliance with the average weighted emissions limit for the existing units participating in the emissions averaging option as determined in § 63.10009(f) and (g);

* * * * *

18. Revise § 63.10030(e)(7)(i) to read as follows:

What notifications must I submit and when?
* * * * *

(e) * * *

(7) * * *

(i) A summary of the results of the annual performance tests and documentation of any operating limits that were reestablished during this test, if applicable. If you are conducting stack tests once every 3 years consistent with § 63.10006(b), the date of the last three stack tests, a comparison of the emission level you achieved in the last three stack tests to the 50 percent emission limit threshold required in § 63.10006(i), and a statement as to whether there have been any operational changes since the last stack test that could increase emissions.

* * * * *

19. Revise § 63.10031(c)(4) to read as follows:

What reports must I submit and when?
* * * * *

(c) * * *

(4) Include the date of the most recent tune-up for each unit subject to the requirement to conduct a performance tune-up according to § 63.10021(e). Include the date of the most recent burner inspection if it was not done every 36 (or 48) months and was delayed until the next scheduled unit shutdown.

* * * * *

20. In § 63.10042, revise the definition “Non-mercury (Hg) HAP metals” and add the definition “Oil” to read as follows:

What definitions apply to this subpart?
* * * * *

Non-mercury (Hg) HAP metals means Antimony (Sb), Arsenic (As), Beryllium (Be), Cadmium (Cd), Chromium (Cr), Cobalt (Co), Lead (Pb), Manganese (Mn), Nickel (Ni), and Selenium (Se).

Oil means crude oil or petroleum or a fuel derived from crude oil or petroleum, including distillate and residual oil, solid oil-derived fuel (e.g., petroleum coke) and gases derived from solid oil-derived fuels (not meeting the definition of natural gas).

* * * * *

22. Revise table 2 and table 7 to Subpart UUUUU of Part 63 to read as follows:

Tables to Subpart UUUUU of Part 63

* * * * *

Table 2 to Subpart UUUUU of Part 63—Emission Limits for Existing EGUs

[As stated in § 63.9991, you must comply with the following applicable emission limits] 1

If your EGU is in this subcategory . . .For the following pollutants . . .You must meet the following emission limits and work practice standards . . .Using these requirements, as appropriate (e.g., specified sampling volume or test run duration) and limitations with the test methods in Table 5 . . .
1. Coal-fired unit not low rank virgin coala. Filterable particulate matter (PM)3.0E-2 lb/MMBtu or 3.0E-1 lb/MWh.2Collect a minimum of 1 dscm per run.
OROR
Total non-Hg HAP metals5.0E-5 lb/MMBtu or 5.0E-1 lb/GWh.Collect a minimum of 1 dscm per run.
OROR
Individual HAP metals:Collect a minimum of 3 dscm per run.
Antimony (Sb)8.0E-1 lb/TBtu or 8.0E-3 lb/GWh.
Arsenic (As)1.1E0 lb/TBtu or 2.0E-2 lb/GWh.
Beryllium (Be)2.0E-1 lb/TBtu or 2.0E-3 lb/GWh.
Cadmium (Cd)3.0E-1 lb/TBtu or 3.0E-3 lb/GWh.
Chromium (Cr)2.8E0 lb/TBtu or 3.0E-2 lb/GWh.
Cobalt (Co)8.0E-1 lb/TBtu or 8.0E-3 lb/GWh.
Lead (Pb)1.2E0 lb/TBtu or 2.0E-2 lb/GWh.
Manganese (Mn)4.0E0 lb/TBtu or 5.0E-2 lb/GWh.
Nickel (Ni)3.5E0 lb/TBtu or 4.0E-2 lb/GWh.
Selenium (Se)5.0E0 lb/TBtu or 6.0E-2 lb/GWh.
b. Hydrogen chloride (HCl)2.0E-3 lb/MMBtu or 2.0E-2 lb/MWh.For Method 26A, collect a minimum of 0.75 dscm per run; for Method 26, collect a minimum of 120 liters per run.
For ASTM D6348-03 3 or Method 320, sample for a minimum of 1 hour.
OR
Sulfur dioxide (SO2) 42.0E-1 lb/MMBtu or 1.5E0 lb/MWh.SO2 CEMS.
c. Mercury (Hg)1.2E0 lb/TBtu or 1.3E-2 lb/GWhLEE Testing for 30 days with 10 days maximum per Method 30B run or Hg CEMS or sorbent trap monitoring system only.
2. Coal-fired unit low rank virgin coala. Filterable particulate matter (PM)3.0E-2 lb/MMBtu or 3.0E-1 lb/MWh.2Collect a minimum of 1 dscm per run.
OROR
Total non-Hg HAP metals5.0E-5 lb/MMBtu or 5.0E-1 lb/GWh.Collect a minimum of 1 dscm per run.
OROR
Individual HAP metals:Collect a minimum of 3 dscm per run.
Antimony (Sb)8.0E-1 lb/TBtu or 8.0E-3 lb/GWh.
Arsenic (As)1.1E0 lb/TBtu or 2.0E-2 lb/GWh.
Beryllium (Be)2.0E-1 lb/TBtu or 2.0E-3 lb/GWh.
Cadmium (Cd)3.0E-1 lb/TBtu or 3.0E-3 lb/GWh.
Chromium (Cr)2.8E0 lb/TBtu or 3.0E-2 lb/GWh.
Cobalt (Co)8.0E-1 lb/TBtu or 8.0E-3 lb/GWh.
Lead (Pb)1.2E0 lb/TBtu or 2.0E-2 lb/GWh.
Manganese (Mn)4.0E0 lb/TBtu or 5.0E-2 lb/GWh.
Nickel (Ni)3.5E0 lb/TBtu or 4.0E-2 lb/GWh.
Selenium (Se)5.0E0 lb/TBtu or 6.0E-2 lb/GWh.
b. Hydrogen chloride (HCl)2.0E-3 lb/MMBtu or 2.0E-2 lb/MWh.For Method 26A, collect a minimum of 0.75 dscm per run; for Method 26, collect a minimum of 120 liters per run.
For ASTM D6348-03 3 or Method 320, sample for a minimum of 1 hour.
OR
Sulfur dioxide (SO2) 42.0E-1 lb/MMBtu or 1.5E0 lb/MWh.SO2 CEMS.
c. Mercury (Hg)4.0E0 lb/TBtu or 4.0E-2 lb/GWhLEE Testing for 30 days with 10 days maximum per Method 30B run or Hg CEMS or sorbent trap monitoring system only.
3. IGCC unita. Filterable particulate matter (PM)4.0E-2 lb/MMBtu or 4.0E-1 lb/MWh.2Collect a minimum of 1 dscm per run.
OROR
Total non-Hg HAP metals6.0E-5 lb/MMBtu or 5.0E-1 lb/GWh.Collect a minimum of 1 dscm per run.
OROR
Individual HAP metals:Collect a minimum of 2 dscm per run.
Antimony (Sb)1.4E0 lb/TBtu or 2.0E-2 lb/GWh.
Arsenic (As)1.5E0 lb/TBtu or 2.0E-2 lb/GWh.
Beryllium (Be)1.0E-1 lb/TBtu or 1.0E-3 lb/GWh.
Cadmium (Cd)1.5E-1 lb/TBtu or 2.0E-3 lb/GWh.
Chromium (Cr)2.9E0 lb/TBtu or 3.0E-2 lb/GWh.
Cobalt (Co)1.2E0 lb/TBtu or 2.0E-2 lb/GWh.
Lead (Pb)1.9E+2 lb/TBtu or 1.8E0 lb/GWh.
Manganese (Mn)2.5E0 lb/TBtu or 3.0E-2 lb/GWh.
Nickel (Ni)6.5E0 lb/TBtu or 7.0E-2 lb/GWh.
Selenium (Se)2.2E+1 lb/TBtu or 3.0E-1 lb/GWh.
b. Hydrogen chloride (HCl)5.0E-4 lb/MMBtu or 5.0E-3 lb/MWh.For Method 26A, collect a minimum of 1 dscm per run; for Method 26, collect a minimum of 120 liters per run.
For ASTM D6348-03 3 or Method 320, sample for a minimum of 1 hour.
c. Mercury (Hg)2.5E0 lb/TBtu or 3.0E-2 lb/GWhLEE Testing for 30 days with 10 days maximum per Method 30B run or Hg CEMS or sorbent trap monitoring system only.
4. Liquid oil-fired unit—continental (excluding limited-use liquid oil-fired subcategory units)a. Filterable particulate matter (PM)3.0E-2 lb/MMBtu or 3.0E-1 lb/MWh.2Collect a minimum of 1 dscm per run.
OROR
Total HAP metals8.0E-4 lb/MMBtu or 8.0E-3 lb/MWh.Collect a minimum of 1 dscm per run.
OROR
Individual HAP metals:Collect a minimum of 1 dscm per run.
Antimony (Sb)1.3E+1 lb/TBtu or 2.0E-1 lb/GWh.
Arsenic (As)2.8E0 lb/TBtu or 3.0E-2 lb/GWh.
Beryllium (Be)2.0E-1 lb/TBtu or 2.0E-3 lb/GWh.
Cadmium (Cd)3.0E-1 lb/TBtu or 2.0E-3 lb/GWh.
Chromium (Cr)5.5E0 lb/TBtu or 6.0E-2 lb/GWh.
Cobalt (Co)2.1E+1 lb/TBtu or 3.0E-1 lb/GWh.
Lead (Pb)8.1E0 lb/TBtu or 8.0E-2 lb/GWh.
Manganese (Mn)2.2E+1 lb/TBtu or 3.0E-1 lb/GWh.
Nickel (Ni)1.1E+2 lb/TBtu or 1.1E0 lb/GWh.
Selenium (Se)3.3E0 lb/TBtu or 4.0E-2 lb/GWh.
Mercury (Hg)2.0E-1 lb/TBtu or 2.0E-3 lb/GWh.For Method 30B sample volume determination (Section 8.2.4), the estimated Hg concentration should nominally be <1/2; the standard.
b. Hydrogen chloride (HCl)2.0E-3 lb/MMBtu or 1.0E-2 lb/MWh.For Method 26A, collect a minimum of 1 dscm per Run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348-03 3 or Method 320, sample for a minimum of 1 hour.
c. Hydrogen fluoride (HF)4.0E-4 lb/MMBtu or 4.0E-3 lb/MWh.For Method 26A, collect a minimum of 1 dscm per run; for Method 26, collect a minimum of 120 liters per run.
For ASTM D6348-03 3 or Method 320, sample for a minimum of 1 hour.
5. Liquid oil-fired unit—non-continental (excluding limited-use liquid oil-fired subcategory units)a. Filterable particulate matter (PM)3.0E-2 lb/MMBtu or 3.0E-1 lb/MWh.2Collect a minimum of 1 dscm per run.
OROR
Total HAP metals6.0E-4 lb/MMBtu or 7.0E-3 lb/MWh.Collect a minimum of 1 dscm per run.
OROR
Individual HAP metals:Collect a minimum of 2 dscm per run.
Antimony (Sb)2.2E0 lb/TBtu or 2.0E-2 lb/GWh.
Arsenic (As)4.3E0 lb/TBtu or 8.0E-2 lb/GWh.
Beryllium (Be)6.0E-1 lb/TBtu or 3.0E-3 lb/GWh.
Cadmium (Cd)3.0E-1 lb/TBtu or 3.0E-3 lb/GWh.
Chromium (Cr)3.1E+1 lb/TBtu or 3.0E-1 lb/GWh.
Cobalt (Co)1.1E+2 lb/TBtu or 1.4E0 lb/GWh.
Lead (Pb)4.9E0 lb/TBtu or 8.0E-2 lb/GWh.
Manganese (Mn)2.0E+1 lb/TBtu or 3.0E-1 lb/GWh.
Nickel (Ni)4.7E+2 lb/TBtu or 4.1E0 lb/GWh.
Selenium (Se)9.8E0 lb/TBtu or 2.0E-1 lb/GWh.
Mercury (Hg)4.0E-2 lb/TBtu or 4.0E-4 lb/GWh.For Method 30B sample volume determination (Section 8.2.4), the estimated Hg concentration should nominally be <1/2; the standard.
b. Hydrogen chloride (HCl)2.0E-4 lb/MMBtu or 2.0E-3 lb/MWh.For Method 26A, collect a minimum of 1 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348-03 3 or Method 320, sample for a minimum of 2 hours.
c. Hydrogen fluoride (HF)6.0E-5 lb/MMBtu or 5.0E-4 lb/MWh.For Method 26A, collect a minimum of 3 dscm per run. For ASTM D6348-03 3 or Method 320, sample for a minimum of 2 hours.
6. Solid oil-derived fuel-fired unita. Filterable particulate matter (PM)8.0E-3 lb/MMBtu or 9.0E-2 lb/MWh.2Collect a minimum of 1 dscm per run.
OROR
Total non-Hg HAP metals4.0E-5 lb/MMBtu or 6.0E-1 lb/GWh.Collect a minimum of 1 dscm per run.
OROR
Individual HAP metalsCollect a minimum of 3 dscm per run.
Antimony (Sb)8.0E-1 lb/TBtu or 7.0E-3 lb/GWh.
Arsenic (As)3.0E-1 lb/TBtu or 5.0E-3 lb/GWh.
Beryllium (Be)6.0E-2 lb/TBtu or 5.0E-4 lb/GWh.
Cadmium (Cd)3.0E-1 lb/TBtu or 4.0E-3 lb/GWh.
Chromium (Cr)8.0E-1 lb/TBtu or 2.0E-2 lb/GWh.
Cobalt (Co)1.1E0 lb/TBtu or 2.0E-2 lb/GWh.
Lead (Pb)8.0E-1 lb/TBtu or 2.0E-2 lb/GWh.
Manganese (Mn)2.3E0 lb/TBtu or 4.0E-2 lb/GWh.
Nickel (Ni)9.0E0 lb/TBtu or 2.0E-1 lb/GWh.
Selenium (Se)1.2E0 lb/TBtu or 2.0E-2 lb/GWh.
b. Hydrogen chloride (HCl)5.0E-3 lb/MMBtu or 8.0E-2 lb/MWh.For Method 26A, collect a minimum of 0.75 dscm per run; for Method 26, collect a minimum of 120 liters per run.
For ASTM D6348-03 3 or Method 320, sample for a minimum of 1 hour.
OR
Sulfur dioxide (SO2) 43.0E-1 lb/MMBtu or 2.0E0 lb/MWh.SO2 CEMS.
c. Mercury (Hg)2.0E-1 lb/TBtu or 2.0E-3 lb/GWh.LEE Testing for 30 days with 10 days maximum per Method 30B run or Hg CEMS or Sorbent trap monitoring system only.
1 For LEE emissions testing for total PM, total HAP metals, individual HAP metals, HCl, and HF, the required minimum sampling volume must be increased nominally by a factor of two.
2 Gross electric output.
3 Incorporated by reference, see § 63.14.
4 You may not use the alternate SO2 limit if your EGU does not have some form of FGD system and SO2 CEMS installed.
* * * * *

Table 7 to Subpart UUUUU of Part 63—Demonstrating Continuous Compliance

[As stated in § 63.10021, you must show continuous compliance with the emission limitations for affected sources according to the following]

If you use one of the following to meet applicable emissions limits, operating limits, or work practice standards . . .You demonstrate continuous compliance by . . .
1. CEMS to measure filterable PM, SO2, HCl, HF, or Hg emissions, or using a sorbent trap monitoring system to measure HgCalculating the 30- (or 90-) boiler operating day rolling arithmetic average emissions rate in units of the applicable emissions standard basis at the end of each boiler operating day using all of the quality assured hourly average CEMS or sorbent trap data for the previous 30-boiler operating days, excluding data recorded during periods of startup or shutdown.
2. PM CPMS to measure compliance with a parametric operating limitCalculating the arithmetic 30-boiler operating day rolling average of all of the quality assured hourly average PM CPMS output data (e.g., milliamps, PM concentration, raw data signal) collected for all operating hours for the previous 30 boiler operating days, excluding data recorded during periods of startup or shutdown.
3. Site-specific monitoring for liquid oil-fired units for HCl and HF emission limit monitoringIf applicable, by conducting the monitoring in accordance with an approved site-specific monitoring plan.
4. Quarterly performance testing for coal-fired, solid oil derived fired, or liquid oil-fired units to measure compliance with one or more applicable emissions limit in Table 1 or 2Calculating the results of the testing in units of the applicable emissions standard.
5. Conducting periodic performance tune-ups of your EGU(s)Conducting periodic performance tune-ups of your EGU(s), as specified in § 63.10021(e).
6. Work practice standards for coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGUs during startupOperating in accordance with Table 3.
7. Work practice standards for coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGUs during shutdownOperating in accordance with Table 3.
* * * * *

23. In Appendix A to Subpart UUUUU of Part 63, revise paragraphs 6.2.1.4, 6.2.2.3, 7.2.4, 7.2.5.3.4, to read as follows:

Appendix A to Subpart UUUUU—Hg Monitoring Provisions

* * * * *

6.2.1.4 The heat input-based Hg emission rate limit in Table 2 to this subpart must be met on a 30 boiler operating day rolling average basis, except as otherwise provided in § 63.10009(a)(2). Use Equation 19-19 in EPA Method 19 to calculate the Hg emission rate for each averaging period. The term Ehj in Equation 19-19 must be in the units of the applicable emission limit. Do not include non-operating hours with zero emissions in the average.

* * * * *

6.2.2.3 The applicable electrical output-based Hg emission rate limit in Table 1 or 2 to this subpart must be met on a 30-boiler operating day rolling average basis, except as otherwise provided in § 63.10009(a)(2). Use Equation A-5 of this section to calculate the Hg emission rate for each averaging period.

Where:

E ̄o = Hg emission rate for the averaging period (lb/GWh).

Echo = Electrical output-based hourly Hg emission rate for unit or stack operating hour “h” in the averaging period, from Equation A-4 of this section (lb/GWh).

n = Number of unit or stack operating hours in the averaging period in which valid data were obtained for all parameters.

(Note: Do not include non-operating hours with zero emission rates in the average).

* * * * *

7.2.4 Certification, Recertification, and Quality-Assurance Test Reporting. Except for daily QA tests of the required monitoring systems (i.e., calibration error tests and flow monitor interference checks), the results of all required certification, recertification, and quality-assurance tests described in paragraphs 7.1.9.1 through 7.1.9.7 of this section (except for test results previously submitted, e.g., under the ARP) shall be submitted electronically, using the ECMPS Client Tool, either prior to or concurrent with the relevant quarterly electronic emissions report.

* * * * *

7.2.5.3.4 The results of all daily calibration error tests of the Hg CEMS, as described in paragraph 7.1.9.1 of this section and (if applicable) the results of all daily flow monitor interference checks.

* * * * *

[FR Doc. 2012-8703 Filed 4-18-12; 8:45 am]

BILLING CODE 6560-50-P