Vol. 81 Wednesday, 

No. 66 April 6, 2016 

Part IV 

Environmental Protection Agency 

40 CFR Parts 60 and 63 

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-CommercialInstitutional, and Small Industrial-Commercial-Institutional Steam Generating 

Units; Technical Correction; Final Rule 


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20172 Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 60 and 63 

[EPA–HQ–OAR–2009–0234 and EPA–HQ– 

OAR–2011–0044; FRL–9942–28–OAR] 

RIN 2060–AS41 

National Emission Standards for 

Hazardous Air Pollutants From Coaland Oil-Fired Electric Utility Steam 

Generating Units and Standards of 

Performance for Fossil-Fuel-Fired 

Electric Utility, Industrial-CommercialInstitutional, and Small IndustrialCommercial-Institutional Steam 

Generating Units; Technical Correction 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule; technical corrections. 

SUMMARY: This action finalizes the 

technical corrections that the 

Environmental Protection Agency (EPA) 

proposed on February 17, 2015, to 

correct and clarify certain text of the 

EPA’s regulations regarding ‘‘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-CommercialInstitutional Steam Generating Units’’. 

We are also taking final action to 

remove the rule provision establishing 

an affirmative defense for malfunction. 

DATES: The effective date of this rule is 

April 6, 2016. 

ADDRESSES: Docket. The EPA has 

established two dockets for this action: 

Docket ID No. EPA–HQ–OAR–2011– 

0044 (new source performance 

standards (NSPS) action) and Docket ID 

No. EPA–HQ–OAR–2009–0234 

(Mercury and Air Toxics Standards 

(MATS) action). All documents in the 

dockets are listed in the http://

www.regulations.gov index. 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, 

will be publicly available only in hard 

copy form. Publicly available docket 

materials are available either 

electronically in http://

www.regulations.gov or in hard copy at 

the EPA Docket Center, Room 3334, 

EPA WJC West Building, 1301 

Constitution Avenue NW., Washington, 

DC 20004. 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: For 

questions about the MATS action: Mr. 

Jim Eddinger, 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– 

5426; fax number (919) 541–5450; email 

address: eddinger.jim@epa.gov. For 

questions about the 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: 

A. How can I get copies of this 

document and other related 

information? 

This Federal Register document and 

the document titled ‘‘Summary of 

Public Comments and Responses: 

MATS and Utility NSPS Technical 

Corrections’’ (TC RTC) are available in 

the dockets the EPA established under 

Docket ID No. EPA–HQ–OAR–2009– 

0234 and Docket ID No. EPA–HQ–OAR– 

2011–0044. The TC RTC is available in 

both the MATS and Utility NSPS 

dockets by conducting a search of the 

title ‘‘Summary of Public Comments and 

Responses: MATS and Utility NSPS 

Technical Corrections.’’ In addition to 

being available in the docket, electronic 

copies of these documents are available 

on the www.regulations.gov Web site. 

This Federal Register document and the 

TC RTC can also be found on the EPA’s 

Technology Transfer Network (TTN) 

Web site at http://www.epa.gov/ttn/atw/ 

utility/utilitypg.html. 

B. Judicial Review 

Under CAA section 307(b)(1), judicial 

review of this final rule is available only 

by filing a petition for review in the U.S. 

Court of Appeals for the District of 

Columbia Circuit by June 6, 2016. Under 

CAA section 307(d)(7)(B), only an 

objection to this final rule that was 

raised with reasonable specificity 

during the period for public comment 

can be raised during judicial review. 

Note, under CAA section 307(b)(2), the 

requirements established by this final 

rule may not be challenged separately in 

any civil or criminal proceedings 

brought by the EPA to enforce these 

requirements. 

I. Background 

The final Clean Air Act (CAA) rules 

published in the Federal Register on 

February 16, 2012 (77 FR 9303), 

establish national emission standards 

for hazardous air pollutants (NESHAP) 

from coal- and oil-fired electric utility 

steam generating units (EGUs), referred 

to as ‘‘MATS,’’ and NSPS for fossil-fuelfired electric utility, industrialcommercial-institutional, and small 

industrial-commercial-institutional 

steam generating units, referred to as the 

‘‘Utility NSPS’’. 

In the February 17, 2015, Federal 

Register (80 FR 8442), the EPA 

proposed to correct certain regulatory 

text. The proposed corrections were 

categorized generally as follows: (a) 

Resolution of conflicts between 

preamble and regulatory text, (b) 

corrections that were inadvertently not 

made that the EPA stated it would make 

in response to comments, and (c) 

clarification of language in regulatory 

text. In the proposed rule, the EPA 

identified each proposed technical 

correction to the regulatory text as 

found in the Code of Federal 

Regulations (i.e., 40 CFR). Table 1 of this 

preamble lists the proposed revisions to 

the regulatory text that the EPA is 

finalizing. In Table 2 below, the EPA 

lists additional changes that the Agency 

determined were necessary to conform 

to changes the Agency included in the 

proposed rule. 


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Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 20173 

TABLE 1—SUMMARY OF PROPOSED TECHNICAL CORRECTIONS AND CLARIFICATIONS BEING FINALIZED

Section of subpart Da 

(40 CFR part 60) 

Description of correction 

(40 CFR part 60) 

40 CFR 60.48Da(f) .............................................. Revise procedures for calculating compliance with the NSPS daily average particulate matter 

(PM) emission limit using PM continuous emission monitoring system (CEMS). 

Section of subpart UUUUU 

(40 CFR part 63) 

Description of correction 

(40 CFR part 63) 

40 CFR 63.9983(a) ............................................. Revise to clarify that MATS does not apply to either major or area source combustion turbines, except for integrated gasification combined cycle (IGCC) units. 

40 CFR 63.9983(b) and (c) ................................. Revise consistent with the definitional changes in 40 CFR 63.10042. 

40 CFR 63.9983(e) ............................................. Add to clarify applicability to units meeting the definition of a natural gas-fired EGU in MATS, 

and, because they combust greater than 10 percent biomass, also meet the definition of a 

biomass-fired boiler in the Industrial Boiler NESHAP (subpart DDDDD). 

40 CFR 63.9991(c)(1) and (2) ............................ Revise to clarify the conditions that are required in order to use the alternate sulfur dioxide 

(SO2) limit. 

40 CFR 63.10000(c)(1)(i)(A) and 63.10005(h) ... Revise to clarify the provisions of units designated as being low emitting EGUs (LEE) when an 

acid gas scrubber and a bypass stack are present. 

40 CFR 63.10000(c)(1)(i)(C) ............................... Add to allow EGUs the ability to seek LEE status if their bypass stacks that are able to measure emissions and to allow EGUs with LEE status the ability to bypass emissions control 

devices during emergency periods. 

40 CFR 63.10000(c)(2)(iii) .................................. Revise to state that EGU choosing to use quarterly testing and parametric monitoring for hydrogen fluoride (HF) or hydrogen chloride (HCl) compliance must include the continuous 

monitoring systems (CMS) in their site-specific monitoring plans. 

40 CFR 63.10000(m) .......................................... Add to clarify that EGUs choosing to meet the work practice standards contained in paragraph 

(2) of the definition of startup may verify, instead of certify, monitoring systems used to meet 

the work practice standards. 

40 CFR 63.10001 ................................................ Revise to remove the affirmative defense provisions. 

40 CFR 63.10005(a) ........................................... Revise to clarify that different compliance demonstrations may require different and additional 

types of data collection and to clarify the date by which compliance must be demonstrated 

for existing EGUs. 

40 CFR 63.10005(a)(2) ....................................... Revise to clarify the date by which compliance must be demonstrated for EGUs using CMS or 

sorbent trap monitoring systems. 

40 CFR 63.10005(a)(2)(i) .................................... Revise to clarify applicability of the provision to both the 30- and 90-boiler operating day performance testing requirements. 

40 CFR 63.10005(b)(6) ....................................... Add to clarify the date EGUs must begin conducting required stack tests when stack test data 

collected prior to the applicable compliance date are submitted to satisfy initial performance 

test. 

40 CFR 63.10005(d)(3) and (d)(4)(i) ................... Revise to more clearly state when compliance must be demonstrated. 

40 CFR 63.10005(f) ............................................ Revise to clarify when sources must complete the initial tune-up after the compliance date, 

and the timing for subsequent tune-ups when the initial tune-up is conducted prior to the 

compliance date. 

40 CFR 63.10005(h)(3) ....................................... Revise to clarify that the alternate 30- and 90-day averaging provisions are both applicable to 

mercury (Hg) emission limits. 

40 CFR 63.10005(i)(4) ........................................ Revise to delete paragraphs (iii) and (iv). The identified test methods are not for determining 

fuel moisture content, as required in the provision. 

40 CFR 63.10006(f) ............................................ Revise to specify EGU operational status with respect to performance testing; the requirements if the performance testing schedule is missed; and intervals between performance 

tests. 

40 CFR 63.10009(a)(2) and (a)(2)(i) ................... Revise to clarify that the 90-boiler operating day averaging period is an option for Hg emissions from non-low rank virgin coal-fired EGUs. 

40 CFR 63.10009(b)(1) ....................................... Revise to clarify group eligibility equations 1a and 1b. 

40 CFR 63.10009(b)(2), (b)(3), (f)(2), (g)(1), 

(g)(2), and (j)(1)(ii).

Revise to correct the term ‘‘gross electric output’’ to ‘‘gross output’’ which is the term defined 

in 40 CFR 63.10042. 

40 CFR 63.10009(f) ............................................ Revise to clarify the conditions for determining the ability of the emissions averaging group to 

meet the emissions limit and to clarify use of the alternate Hg emission limit. 

40 CFR 63.10010(a)(4) ....................................... Revise to add requirement to route exhaust gases that bypass emissions control devices 

through stacks that contain monitoring so that emissions can be measured and to clarify 

that hours that a bypass stack is in use are to be counted as hours of deviation from monitoring requirements. 

40 CFR 63.10010(f)(3) ........................................ Revise to clarify that 30-boiler operating day rolling averages are based only on valid hourly 

SO2 emission rates. 

40 CFR 63.10010(h)(6)(i) and (ii), (i)(5)(i)(A) and 

(B), and (j)(4)(i)(A) and (B).

Revise to clarify that data collected during certain periods are not to be included in compliance 

assessments but such periods are to be included in annual deviation reports. 

40 CFR 63.10010(j)(l)(i) ...................................... Revise to replace the incorrect reference to § 63.7(e) with the correct reference to § 63.8(d)(2). 

40 CFR 63.10010(l) and (l)(4) ............................. Revise to clarify that EGU owners or operators who choose to meet the work practice standards contained in paragraph (2) of the definition of startup may verify, instead of certify, 

monitoring systems used. 

40 CFR 63.10011(b) ........................................... Revise to remove the incorrect reference to Table 4 and to replace the incorrect reference to 

Table 7 with the correct reference to Table 6. 


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TABLE 1—SUMMARY OF PROPOSED TECHNICAL CORRECTIONS AND CLARIFICATIONS BEING FINALIZED—Continued 

Section of subpart UUUUU 

(40 CFR part 63) 

Description of correction 

(40 CFR part 63) 

40 CFR 63.10011(c)(1) and (2) .......................... Revise to clarify the date by which compliance must be demonstrated by EGUs that use 

CEMS or sorbent trap monitoring systems and to clarify in 40 CFR 63.10011(c)(1) that the 

alternate Hg emission limit may be used. 

40 CFR 63.10011(e) ........................................... Revise to replace ‘‘according to’’ with ‘‘in accordance with.’’ 

40 CFR 63.10011(g)(4)(v)(A) and Table 3 ......... Revise to clarify our intent by changing ‘‘to the maximum extent possible’’ to ‘‘to the maximum 

extent possible, taking into account boiler or control device integrity.’’ 

40 CFR 63.10020(e) ........................................... Revise to clarify that it applies only to EGU owners or operators who choose to meet the work 

practice standards contained in paragraph (2) of the definition of startup. In addition, the undefined term ‘‘electrical load’’ has been replaced with the defined term ‘‘gross output’’ and 

the incorrect terms ‘‘liquid to fuel ratio’’ and ‘‘the differential pressure of the liquid’’ have 

been replaced with the correct terms ‘‘liquid to flue gas ratio’’ and ‘‘the pressure drop across 

the scrubber.’’ 

40 CFR 63.10021(d)(3) ....................................... Revise to clarify the type of monitoring that is to be used to demonstrate compliance. 

40 CFR 63.10021(e) ........................................... Revise to clarify the condition that allows delay of burner inspections for initial tune-ups. 

40 CFR 63.10021(e)(9) ....................................... Revise to clarify the dates that tune-ups must be reported. 

40 CFR 63.10023(b) and Table 6 ....................... Revise to clarify that all EGUs using PM continuous parametric monitoring systems (CPMS) 

for compliance purposes are to follow the same procedure for determining the operating 

limit. 

40 CFR 63.10030(e)(1) ....................................... Revise to replace the phrase ‘‘identification of which subcategory the source is in’’ with ‘‘identification of the subcategory of the source.’’ 

40 CFR 63.10030(e)(7)(i) .................................... Revise to delete and reserve since subsequent performance tests are not part of the Notification of Compliance Status. 

40 CFR 63.10030(e)(7)(iii) .................................. Add to establish the procedures by which an EGU owner or operator may switch between 

mass per heat input and mass per gross output emission limits. 

40 CFR 63.10030(e)(8)(i) .................................... Revise to clarify that it applies only to EGU owners or operators who choose to meet the work 

practice standards contained in paragraph (2) of the definition of startup. 

Revise to clarify that PM control device efficiencies and PM emission rates are those of periods other than startup and shutdown periods. 

40 CFR 63.10030(e)(8)(ii) ................................... Revise to remove the requirement for use of an independent professional engineer. 

40 CFR 63.10030(f) ............................................ Revise to add notification requirements for EGUs that move in and out of MATS applicability. 

40 CFR 63.10031(c)(4) ....................................... Revise to clarify the reporting requirements for EGU tune-ups. 

40 CFR 63.10031(c)(5) ....................................... Revise to clarify that it applies only to EGU owners or operators who choose to meet the work 

practice standards contained in paragraph (2) of the definition of startup. 

40 CFR 63.10031(c)(6) ....................................... Revise to add emergency bypass reporting for EGUs with LEE status. 

40 CFR 63.10032(f) ............................................ Revise to clarify that the requirements of § 63.10032(f)(1) apply only to those EGU owners or 

operators who choose to meet the work practice standards contained in paragraph (1) of 

the definition of startup, while the requirements of § 63.10032(f)(2) apply only to those EGU 

owners or operators who choose to meet the work practice standards contained in paragraph (2) of the definition of startup. 

40 CFR 63.10042 ................................................ The definitions of ‘‘Coal-fired electric utility steam generating unit,’’ ‘‘Coal refuse,’’ ‘‘Fossil fuelfired,’’ ‘‘Integrated gasification combined cycle electric utility steam generating unit or 

IGCC,’’ ‘‘Limited-use liquid oil-fired subcategory,’’ ‘‘Natural gas-fired electric utility steam 

generating unit,’’ and ‘‘Oil-fired electric utility steam generating unit’’ are revised to clarify the 

period of time to be included in determining the source’s applicability to the MATS. 

A definition of ‘‘neural network’’ is added because the term is used in 40 CFR 63.10005(f), 

63.10006(i), and 63.10021(e) and Table 3 to subpart UUUUU of Part 63 but is not defined. 

Table 1 to subpart UUUUU of part 63 ................ Revise to correct the term ‘‘gross electric output’’ to ‘‘gross output’’ which is the term defined 

in 40 CFR 63.10042. 

Table 2 to subpart UUUUU of part 63 ................ Revise to correct the term ‘‘gross electric output’’ to ‘‘gross output’’ which is the term defined 

in 40 CFR 63.10042. Provision 1(c) (the Hg limit for EGUs in the subcategory ‘‘unit designed for coal ≥8,300 Btu/lb’’) is also revised to clarify the applicability of the alternate 90- 

boiler operating day compliance option. 

Table 3 to subpart UUUUU of part 63 ................ Revise as described earlier to clarify the term ‘‘maximum extent possible.’’. 

Table 4 to subpart UUUUU of part 63 ................ Revise to clarify that existing as well as new EGUs using PM CPMS share the same procedures for developing operating limits. 

Table 5 to subpart UUUUU of part 63 ................ Revise to clarify that when using Method 29, the metals matrix spike and recovery levels are 

to be reported. 

Table 6 to subpart UUUUU of part 63 ................ Revise to clarify that existing, as well as new, EGUs using PM CPMS share the same procedures for developing operating limits. 

Table 8 to subpart UUUUU of part 63 ................ Revise to clarify that compliance reports are to include information required by 40 CFR 

63.10031(c)(5) and (6). 

Table 9 to subpart UUUUU of part 63 ................ Revise to correct an inadvertent omission of 30-day notification requirements of 40 CFR 63.9. 

Paragraphs 4.1.1.3 and 5.1.2.3 and Tables A–1 

and A–2 to appendix A.

Revise to adjust Hg CEMS language regarding converters. 

Paragraph 7.1.2.5 to appendix A ........................ Add to require that owners or operators flag EGUs that are part of emission averaging groups. 

Paragraph 3.2.1.2.1 of appendix A ..................... Revise to specifically indicate that Hg gas generators and cylinders are allowed. 

Paragraphs 4.1.1.1, Table A–1, Table A–2, 

5.1.2.1, and 4.1.1.3 of appendix A.

Revise to exclude use of oxidized Hg gas standards for daily calibration of Hg CEMS. 

Paragraph 5.1.2.3 of appendix A ........................ Revise to make the weekly single level system integrity check mandatory.


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Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 20175 

TABLE 1—SUMMARY OF PROPOSED TECHNICAL CORRECTIONS AND CLARIFICATIONS BEING FINALIZED—Continued 

Section of subpart UUUUU 

(40 CFR part 63) 

Description of correction 

(40 CFR part 63) 

Paragraphs 4.1.1.5.2, Table A–1, Table A–2, 

and 4.1.1.5 of appendix A.

Revise to provide an alternative relative accuracy test audit (RATA) procedure for EGUs with 

low emissions. 

Paragraph 5.2.1 of appendix A ........................... Revise to correct the number of days for sorbent trap use from 14 to 15. 

Paragraph 6.2.2.3 of appendix A ........................ Revise to clarify that the 90-day alternative Hg standard may be used and that electrical output is gross output. 

Paragraph 7.1.2.6 of appendix A ........................ Add to clarify that EGU owners or operators are to keep records of their EGUs that constitute 

emissions averaging groups. 

Paragraphs 2.1, 2.3, 2.3.1, 2.3.2, 3.1, 3.2, 3.3, 

5, 5.1, 5.2, and 5.3 of appendix B.

Revise to clarify that use of Performance Specification (PS) 18, when promulgated, will be allowed. 

Paragraph 5.4 of appendix B .............................. Add as part of the renumbering due to the addition of PS 18. 

Paragraph 8 of appendix B ................................. Revise to accommodate use of PS 18. 

Paragraphs 10.1.8, 10.1.8.1, 10.1.8.1.1, and 

10.1.8.1.2 of appendix B.

Revise as part of the renumbering due to the addition of PS 18. 

Paragraph 10.1.8.1.3 of appendix B ................... Revise to clarify that records of relative accuracy audits (RAAs) are also required. 

Paragraphs 10.1.8.2, 10.1.8.1.2.1, and 

10.1.8.1.2.2 of appendix B.

Revise to clarify the quarterly gas audit recordkeeping requirements for PS 15 and the quarterly data accuracy assessments for PS 18 (which are reserved). 

Paragraph 11.4 of appendix B ............................ Revise to replace the incorrect abbreviation ‘‘i.e.’’ with ‘‘e.g.’’. 

Paragraph 11.4.2 of appendix B ......................... Revise to specify the requirements of the daily beam intensity checks for EGUs using PS 18. 

Paragraph 11.4.3 of Appendix B ......................... Revise to reflect the reporting requirements for PS 15. 

Paragraph 11.4.4 of appendix B ......................... Revise to reserve the reporting requirements for quarterly parameter verification checks for PS 

18. 

Paragraphs 11.4.4.1, 11.4.5, 11.4.5.1, 11.4.6, 

11.4.6.1 of appendix B.

Add to reserve the reporting requirements for quarterly gas audit information and for quarterly 

dynamic spiking for PS 18. 

Paragraph 11.4.7 of appendix B ......................... Add to include reporting requirements for RAAs. 

Paragraphs 11.4.7.1 through 11.4.7.13 of appendix B.Add as part of the renumbering due to the addition of PS 18. 

Paragraph 11.5.3.4 of appendix B ...................... Revise to include reporting requirements for beam intensity checks for PS 18. 

Most of the corrections and 

clarifications remain the same as 

presented in the proposed correction 

document and those changes are being 

finalized without further discussion. 

However, the EPA has made some 

changes in this final rule after 

consideration of the public comments 

received on the proposed correction 

document. The changes are to clarify 

applicability and implementation issues 

associated with proposed changes, and 

the significant changes are discussed 

below in this preamble. A summary of 

the comments received and our 

responses thereto is contained in the 

document ‘‘Summary of Public 

Comments and Responses: MATS and 

Utility NSPS Technical Corrections’’ 

located in the dockets for these 

rulemakings. 

II. Significant Changes Since Proposal 

This section of the preamble 

summarizes the significant changes 

made to the proposed corrections and 

clarifications. 

1. Section 63.9984(f) is revised to add 

‘‘or the EGU’s otherwise applicable 

compliance date established by the EPA 

or the state.’’ A commenter stated that 

the EPA’s proposed revision, which was 

adding ‘‘the date that compliance must 

be demonstrated, as given’’ in § 63.9984, 

to the initial compliance requirements 

in § 63.10005(a) for existing EGUs, does 

not effectively clarify the date that 

compliance must be demonstrated due 

to its reference to § 63.9984 and 

paragraph (f) of § 63.9984 because 

§ 63.9984(b) specifies a compliance date 

of April 16, 2015 for existing EGUs. 

Also, § 63.9984(f), which states the dates 

by which compliance must be 

demonstrated, refers to § 63.9984(b). 

Therefore, we revised § 63.9984(f) 

because specifying a date for existing 

EGUs to demonstrate compliance is 

confusing for existing sources that have 

been granted a compliance extension. 

2. Section 63.10000(n) is added to 

address comments that noted the 

proposed technical corrections did not 

address the permanent conversion to 

natural gas or biomass consistent with 

the proposals outlined in the February 

17, 2015 preamble. In the preamble (see 

80 FR 8447), we stated ‘‘The EPA is also 

proposing that sources that permanently 

convert to natural gas or biomass after 

the compliance date are no longer 

subject to MATS, notwithstanding the 

coal or oil usage the previous 3 calendar 

years.’’ However, we inadvertently did 

not include the necessary language to 

address permanent conversions in the 

proposed regulatory text. For that 

reason, we are revising paragraph (n) to 

incorporate the proposed change as 

outlined in the preamble to the 

proposed rule. 

3. The proposal to revise 

§ 63.10005(b)(1) to change the time 

period allowed for existing EGUs to use 

stack test data collected prior to the 

applicable compliance date has been 

withdrawn. Several commenters did not 

support the proposed revision to change 

the window in which initial compliance 

can be demonstrated, and said that 

EGUs should be allowed to demonstrate 

initial compliance using stack tests 

conducted on or after April 16, 2014. 

Commenters said the EPA’s proposed 

change is unfair, renders investments in 

stack testing useless, and requires 

companies to perform new, unnecessary 

initial compliance testing. For these 

reasons, and because the Agency 

believes earlier stack tests may be 

representative under certain 

circumstances, the EPA is not making 

the proposed change. 

4. Section 63.10006(f) is revised to: (1) 

Correct the minimum time between 

annual performance tests (from 370 to 

320 calendar days); (2) clarify the 

minimum time between annual sorbent 

trap mercury testing for 30-boiler 

operating day low emitting EGU (LEE) 

retests (also 320 calendar days); and (3) 

provide the minimum time between 

annual sorbent trap mercury testing for 

90-boiler operating day LEE retests (230 

calendar days). Commenters correctly 

stated that the 370-day interval for 

annual tests was a typographical error, 

as they would expect the interval to be 

365 days or less. Commenters expressed 

concerns that, while the proposed 

revised § 63.10006(f) specified the time 


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20176 Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 

periods between annual performance 

tests, it did not specify the time periods 

between annual sorbent trap mercury 

testing for either the 30-boiler operating 

day averaging periods or the 90-boiler 

operating day averaging periods. The 

three revisions, listed above, being made 

to § 63.10006(f) address the 

commenters’ concerns. In addition, 

§ 63.10010(i)(2)(i) and (ii) is revised to 

clarify the time periods between 

quarterly, annual, and three year testing 

for particulate matter continuous 

emissions monitoring system (PM 

CEMS) audits. 

5. Section 63.10009(b)(1) is revised to 

clarify group eligibility equations 1a and 

1b. The purpose of the group eligibility 

equations is to provide EGU owners or 

operators a quick method for 

demonstrating initial compliance with 

the emission limits for all units 

participating in the emission averaging 

group using the maximum rated heat 

input or gross output of each unit and 

the results of the initial compliance 

demonstrations. Commenters stated that 

the EPA proposed to drop the double 

summation in the denominator, which 

is a correct step. However, the 

commenters indicated they do not 

understand what the Agency was 

thinking with respect to adding the ‘‘qj’’ 

term in both the numerator and 

denominator and that the EPA defined 

‘‘qj’’ to be the hours in the averaging 

period (720 for 30-day averages and 

2,160 for 90-day averages) because the 

term’s presence in both the numerator 

and denominator cancels out and has no 

effect. Commenters also stated that they 

do not agree that the newly proposed 

group averaging eligibility Equation 1a 

is more useful than the original 

equation. Commenters said both the 

original equation and the newly 

proposed equation are flawed and, thus, 

produce incorrect results. Commenters 

said corrections need to be made to 

either equation that the EPA wants to 

use. Commenters said the stack testing 

components of the equation for each 

unit that is tested need to be weighted 

the same as units that use continuous 

monitoring in order for any equation to 

produce correct calculations. 

Commenters said the original equation 

works for the continuous monitoring 

components, but is flawed because it 

does not properly weight the stack 

testing components, and the newly 

proposed equation is flawed on both 

fronts. Based on the commenters’ 

concerns, the equations have been 

revised so that individual EGU 

characteristics, whether from 

continuous emission monitoring 

systems (CEMS) or stack testing results, 

are easier to input. We agree that the 

added ‘‘qj’’ term and ‘‘rk’’ term have no 

effect, and they have been deleted. We 

are also deleting the ‘‘n’’ term since 

Equations 1a and 1b are to demonstrate 

initial compliance based on using the 

initial compliance results and not 

continuous compliance that is based on 

an averaging period. We have revised 

some of the terms’ descriptions to 

clarify that the emission rates used are 

those determined during the initial 

compliance demonstration. 

6. Section 63.10009(e), (g), and (j)(2) 

are revised to require compliance with 

the weighted average emissions rate at 

all times following the date that 

emissions averaging begins. A 

commenter argued that the EPA must 

also revise these sections to remove the 

specifically identified dates (e.g., April 

16, 2015 and February 16, 2015). We 

agree that the dates within 

§ 63.10009(e), (g), and (j)(2) should be 

removed, and the dates have been 

replaced with ‘‘the date that you begin 

emission averaging.’’ 

7. Section 63.10010(h)(6)(i), 

(i)(5)(i)(A), and (j)(4)(i)(A) and (B) are 

revised to clarify when monitoring 

system quality assurance or quality 

control activities are to be reported. 

Commenters said § 63.10010(h)(6)(i), 

(i)(5)(i)(A), and (j)(4)(i)(A) and (B) 

specify what data from particulate 

matter (PM) continuous parameter 

monitoring system (CPMS), PM CEMS, 

and hazardous air pollutants (HAP) 

metal CEMS must be excluded from 

compliance determinations and that the 

EPA proposed to separate the language 

regarding deviation reporting that 

currently appears at the end of these 

provisions into a separate sentence to 

‘‘ease readability.’’ The commenter 

disagreed that the proposed revision 

improves readability and said that, to 

the contrary, by separating out the 

sentence, the EPA implies that the 

periods when data are not collected 

because of monitoring system 

malfunctions, repairs, required quality 

assurance or quality control, as well as 

periods when a monitoring system is 

out of control, are deviations from 

monitoring requirements, which they 

are not. The commenter is incorrectly 

interpreting the proposed change. 

Periods when data are not collected 

because of monitoring system 

malfunctions are deviations. The 

required quality assurance or quality 

control activities that are deviations 

from monitoring requirements are, as 

stated in § 63.10010(h)(6)(i), (i)(5)(i)(A), 

and (j)(4)(i)(A) and (B), those conducted 

during monitoring systems 

malfunctions. 

8. Section 63.10011(g)(4)(v)(A) is 

revised to change the proposed language 

‘‘to the maximum extent practicable’’ 

back to the language ‘‘to the maximum 

extent possible’’ as in the final rule. 

Commenters said the requirement to use 

clean fuels ‘‘to the maximum extent 

practicable’’ does not even address the 

level of toxic emissions during startup, 

let alone reduce them to the maximum 

extent achievable as is required under 

CAA section 112(d)(2). Commenters 

said, perhaps most importantly, that the 

EPA’s proposed change impermissibly 

assumes that existing older boilers and 

control devices are not capable of being 

upgraded—despite Congress’ mandate 

in CAA section 112(d)(2)–(3) that 

emissions standards and work practices 

reflect what is achievable and actually 

being achieved by the best-performing 

sources. Commenters said further, under 

CAA section 112(d), it is the 

Administrator’s duty to establish 

standards to achieve the required 

emissions reductions—not the duty of 

owners and operators. Commenters said 

the EPA’s purported work practices 

impermissibly allow operators 

themselves to determine the standards 

and their own emission reductions 

achieved (or not) by the requirements. 

Commenters said the EPA’s proposed 

change leaves it up to each operator to 

determine the amount of clean fuel use 

that represents the ‘‘maximum extent 

practicable,’’ and leaves it up to each 

operator to determine what qualifies as 

a ‘‘consideration such as boiler or 

control device integrity.’’ Commenters 

said that even though the requirement 

for clean fuels states that EGUs must 

have sufficient clean fuel capacity to 

engage and operate PM control devices 

within 1 hour of adding the primary fuel 

(and even though a separate work 

practice requires PM controls to be 

engaged and operated within 1 hour), 

these requirements do not establish 

whether and to what point EGUs must 

actually use clean fuels in startups. 

These comments primarily concern 

issues that the EPA did not reopen in 

the proposed document. Because those 

issues were not reopened, the EPA did 

not respond to these comments. We did 

propose to change § 63.10011(g)(4)(v)(A) 

as the commenter states. We continue to 

believe that the use of clean fuels during 

startup must be maximized to reduce 

HAP emissions and have reconsidered 

the proposed change of ‘‘possible’’ to 

‘‘practicable.’’ We believe ‘‘possible’’ is 

a more enforceable standard. The final 

change to § 63.10011(g)(4)(v)(A) is: ‘‘to 

the maximum extent possible, taking 

into account considerations such as 

boiler or control device integrity, 


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Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 20177 

throughout the startup period.’’ This 

language is also included in section 4 of 

Table 3, to clarify that this provision 

applies during periods of shutdown. 

The EPA is not finalizing the 

proposed change because we have 

determined that requiring clean fuel use 

to the maximum extent ‘‘possible’’ is 

more enforceable than the proposed 

change to ‘‘practicable’’, and the Agency 

believes it is critical that the work 

practice be enforceable to ensure that 

sources use as much clean fuel with its 

inherently low HAP content as possible 

when a source’s controls are not yet 

fully engaged. At the same time, we 

believe operators must be able to 

consider the integrity of the EGU system 

when determining the clean fuel use 

that is ‘‘possible’’ for a given unit. We 

believe the final rule addresses both 

considerations. 

9. Section 63.10030(e)(8)(iii) is added 

to allow EGU owners or operators the 

ability to switch between paragraphs 1 

and 2 of the startup definition. 

Commenters requested that switching 

between paragraphs of the definition of 

startup not be prohibited. We have no 

objection to such switching provided 

certain criteria are met. Just as we had 

not considered that EGU owners or 

operators would want to switch between 

mass per year heat input emission limits 

and mass per gross output emission 

limits, but proposed to allow such 

changes provided certain criteria are 

met, we did not consider that an owner 

or operator would want to switch 

between the startup definitions for the 

EGU. Given the commenter’s specific 

request and the EPA’s conditional 

approval based on the already existing 

model given in § 63.10030(e)(7)(iii)(A), 

§ 63.10030(e)(8)(iii) is added to the rule. 

This new section allows EGU owners or 

operators the ability to switch between 

paragraphs 1 and 2 of the startup 

definition provided, among other things, 

that the EGUs involved in the switch are 

identified, that a request is submitted 30 

days prior to the anticipated switch, that 

the request contains certification that all 

previous plans, such as monitoring and 

emissions averaging, are revised, that 

records are maintained, and that the 

new definition is not used until the next 

reporting period after receipt of written 

acknowledgement from the 

Administrator or the delegated authority 

of the switch. 

10. Section 63.10031(c)(4) is revised 

to clarify that the ‘‘date’’ of the tune-up 

is the date the tune-up provisions 

specified in § 63.10021(e)(6) and (7) are 

completed. Commenters noted that 

there will not necessarily be a single 

date associated with completion of an 

EGU’s tune-ups conducted under 

§ 63.10021(e) and suggested that, related 

to the possibility of a delayed burner 

inspection, the Agency make it clear 

that compliance with all requirements 

besides the burner inspection must 

occur by the compliance demonstration 

date, but that the burner inspection may 

be delayed, and to revise the provision 

to recognize that as a result, 

performance of subsequent inspections 

and tune-ups may be on a separate 36- 

month track and some EGUs may have 

‘‘dates’’ rather than a ‘‘date’’ for 

completion of requirements. Regardless 

of when the burner inspection is 

conducted, the tune-up is considered to 

have been conducted on the date the 

combustion optimization is completed. 

The purpose of the tune-up is the 

optimization of the combustion to 

minimize organic HAP, carbon 

monoxide, and nitrogen oxides (NOX) 

and to improve or return the unit to its 

design combustion efficiency (i.e., 

§ 63.10021(e)(6) and (7)). We realize that 

EGUs may need to be taken off-line to 

conduct an inspection of burners. So, 

we allow that inspection to be delayed, 

or as § 63.10021(e) is revised, to be 

performed prior to the tune-up. 

Therefore, subsequent tune-ups must be 

performed within 36 months from when 

the previous tune-up (i.e., the 

requirements of § 63.10021(e)(6) and (7)) 

was completed, and the source must 

conduct the next burner inspection on 

a similar schedule. 

11. Section 63.10031(c)(7) is added to 

include the reporting requirements that 

have been removed from 

§ 63.10030(e)(7)(i). A commenter said 

that there is no reason to submit 

Notification of Compliance Status 

(NOCS) for ongoing 3-year tests that are 

performed to demonstrate that LEE 

status is maintained, so the proposed 

language in § 63.10030(e)(7)(i) should be 

revised. We agree that not only the 

ongoing 3-year LEE retests, but also the 

annual and quarterly LEE retests and 

annual retests that are performed to 

establish operating limits, should not be 

submitted as NOCS. According to the 

introductory text of § 63.10030(e), the 

NOCS is required only for reporting 

initial compliance. Therefore, 

§ 63.10030(e)(7)(i) has been removed 

and reserved, and the reporting 

requirements in § 63.10030(e)(7)(i) have 

been moved to a new place, i.e., 

§ 63.10031(c)(7), and are part of the 

compliance report requirements. 

Likewise, the compliance certification 

and deviation information requirements 

in § 63.10030(e)(5) and (e)(6) apply for 

compliance reports and are replicated in 

new § 63.10031(c)(8) and (9), and each 

of these paragraphs is included in the 

introductory text in § 63.10030(c) and in 

Table 8. 

12. The definitions of ‘‘Coal-fired 

electric utility steam generating unit,’’ 

‘‘Fossil fuel-fired,’’ ‘‘Limited-use liquid 

oil-fired subcategory,’’ and ‘‘Oil-fired 

electric utility steam generating unit’’ in 

§ 63.10042 are further revised to clarify 

the period of time to be included in 

determining the source’s applicability to 

the MATS. 

One commenter indicated that the 

proposed rule does not address 

permanent conversion to natural gas or 

biomass, nor does it make clear that, 

after the first 3 years of compliance, 

EGUs are required to evaluate 

applicability based on coal or oil usage 

from the 3 previous calendars years on 

an annual rolling basis. The commenter 

said that the EPA’s clarifying proposals 

are not clearly outlined in the proposed 

revised definitions. The commenter 

urged the EPA to revise the definition in 

a manner consistent with the proposals 

outlined in the preamble. Several 

commenters indicated the proposed 

changes do not prevent an EGU from 

continuing to be subject to MATS for 

several years after a fuel switch. 

We agree that the proposed 

clarification to the definitions does not 

make it clear that, after the first 3 years 

of compliance, an EGU is required to 

evaluate applicability based on coal or 

oil usage from the 3 previous calendar 

years on an annual rolling basis. Thus, 

we have revised the definitions for 

‘‘Coal-fired electric utility steam 

generating unit,’’ ‘‘Oil-fired electric 

utility steam generating unit,’’ and 

‘‘Fossil fuel-fired’’ to clarify that 

applicability after the first 3 years of 

compliance will be based on coal or oil 

usage from the 3 previous calendar 

years on an annual rolling basis. 

Concerning the permanent fuels 

switch, the EPA explained above that it 

has addressed permanent conversions in 

§ 63.10000(n) of the final rule, as 

discussed in paragraph 2 above. 

13. Appendix A is finalized with all 

proposed revisions with the exception 

of adding an alternative specification for 

the relative accuracy test audit (RATA) 

where commenters provided data to 

support a different approach using an 

absolute value criterion. However, due 

to the current lack of available NISTtraceable elemental Hg gas cylinders, 

owners or operators of EGUs that have 

purchased/installed Hg CEMS that lack 

integrated elemental Hg gas generators 

may continue to use NIST-traceable 

oxidized gases for calibration error tests 

and daily checks until such time that 

NIST-traceable compressed elemental 

Hg gas standards are available and 

traceable with a combined uncertainty 


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20178 Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 

(K=2) of 5 percent. Once those standards 

are available, we will issue a notice of 

availability in the Federal Register. 

Should NIST-traceable oxidized 

mercury reference gases with a 

combined uncertainty of 5% ultimately 

be available, we will consider allowing 

their use for calibration error tests and 

checks. 

14. Appendix B is finalized with all 

proposed revisions except those related 

to sections 10 and 11 regarding 

recordkeeping and reporting for 

hydrogen chloride (HCl) CEMS subject 

to PS 18. Sections 10 and 11 will be 

addressed in the upcoming MATS 

Completion of Electronic Reporting 

Requirements rule. One change has been 

made that was not proposed. A minor 

technical correction has been made to 

section 9.4, requiring the HCl emission 

rates to be reported to 2 significant 

figures in scientific notation, which is 

consistent with the way that the 

emission standards are presented in 

Tables 1 and 2. 

III. Other Corrections and 

Clarifications 

In finalizing the rule, the EPA is 

addressing several other technical 

corrections and clarifications in the 

regulatory language based on public 

comments that were received on the 

February 2015 proposal that the Agency 

determined were necessary to conform 

to changes included in the proposed 

rule, as outlined in Table 2 of this 

preamble. 

TABLE 2—SUMMARY OF TECHNICAL CORRECTIONS AND CLARIFICATIONS SINCE FEBRUARY 17, 2015, PROPOSAL

Section of subpart UUUUU 

(40 CFR part 63) 

Description of correction 

(40 CFR part 63) 

40 CFR 63.10000(a) ........................................... Revise this paragraph by adding ‘‘items 3 and 4’’ to clarify which items in Table 3 must be 

met. 

40 CFR 63.10000(f) ............................................ Revise this paragraph to add ‘‘Except as provided under paragraph (n) of this section’’ due to 

the addition of paragraph (n) clarifying the applicability of a permanent conversion to natural 

gas or biomass. 

40 CFR 63.10000(g) ........................................... Revise this paragraph to add ‘‘Except as provided under paragraph (n) of this section’’ due to 

the addition of paragraph (n) clarifying the applicability of a permanent conversion to natural 

gas or biomass. 

40 CFR 63.10000(i)(1) ........................................ Revise this paragraph to clarify that an EGU, no longer subject to MATS, must be in compliance with applicable CAA section 112 or 129 standards consistent with paragraphs (g) and 

(n). 

40 CFR 63.10005(a) ........................................... Revise this paragraph to replace the terms ‘‘electrical’’ and ‘‘electrical load’’ with the terms 

‘‘gross’’ and ‘‘gross output,’’ respectively, to be consistent with the proposed changes to 

other sections. 

40 CFR 63.10005(a)(2)(ii) ................................... Revise this paragraph to replace the terms ‘‘electrical’’ and ‘‘electrical load’’ with the terms 

‘‘gross’’ and ‘‘gross output,’’ respectively, to be consistent with the proposed changes to 

other sections. 

40 CFR 63.10005(b)(4) ....................................... Revise this paragraph to replace the term ‘‘electrical load’’ with the term ‘‘gross output’’ to be 

consistent with the proposed changes to other sections. 

40 CFR 63.10005(f) ............................................ Revise to be consistent with EPA’s intent, as explained in the preamble to the proposed rule, 

to only clarify the timing of initial and subsequent tune-ups. 

Revise since specifying the date is problematic for sources that have been granted a compliance extension. 

40 CFR 63.10005(h)(3)(i)(D) ............................... Revise this paragraph to replace the term ‘‘electrical load’’ with the term ‘‘gross output’’ to be 

consistent with the proposed changes to other sections. 

40 CFR 63.10005(h)(3)(iii) .................................. Revise this paragraph to replace the term ‘‘electrical load’’ with the term ‘‘gross output’’ to be 

consistent with the proposed changes to other sections. 

40 CFR 63.10007(f)(2) ........................................ Revise this paragraph to replace the term ‘‘electrical load’’ with the term ‘‘gross output’’ to be 

consistent with the proposed changes to other sections. 

40 CFR 63.10009(e) and (j)(2) ........................... Revise since specifying the date is problematic for sources that have been granted a compliance extension. 

40 CFR 63.10010(f)(4) ........................................ Revise this paragraph to replace the term ‘‘electrical load’’ with the term ‘‘gross output’’ to be 

consistent with the proposed changes to other sections. 

40 CFR 63.10021(h)(1) ....................................... Revise this paragraph to replace the term ‘‘electrical load’’ with the term ‘‘gross output’’ to be 

consistent with the proposed changes to other sections. 

Table 5 ................................................................ Revise this table to replace the term ‘‘electrical’’ with the term ‘‘gross’’ to be consistent with 

the proposed changes to other sections. 

Paragraph 7.1.8.5 of appendix A ........................ Revise this paragraph to replace the term ‘‘electrical load’’ with the term ‘‘gross output’’ to be 

consistent with the proposed changes to other sections. 

IV. Affirmative Defense for Violation of 

Emission Standards During 

Malfunction 

The EPA received numerous 

comments on the affirmative defense to 

civil penalties for violations caused by 

malfunctions that the EPA proposed to 

remove in the current rule. Several 

commenters supported the removal of 

the affirmative defense for malfunctions. 

Other commenters opposed the removal 

of the affirmative defense provision. 

As stated in the February 17, 2015, 

proposal, the United States Court of 

Appeals for the District of Columbia 

Circuit vacated an affirmative defense in 

one of the EPA’s CAA section 112(d) 

regulations. NRDC v. EPA, No. 10–1371 

(D.C. Cir. April 18, 2014) 2014 U.S. 

App. LEXIS 7281 (vacating affirmative 

defense provisions in CAA section 

112(d) rule establishing emission 

standards for Portland cement kilns). 

The court found that the EPA lacked 

authority to establish an affirmative 

defense for private civil suits and held 

that under the CAA, the authority to 

determine civil penalty amounts in such 

cases lies exclusively with the courts, 

not the EPA. Specifically, the court 

found: ‘‘As the language of the statute 

makes clear, the courts determine, on a 

case-by-case basis, whether civil 

penalties are ‘appropriate.’ ’’ See NRDC, 

2014 U.S. App. LEXIS 7281 at *21 

(‘‘[U]nder this statute, deciding whether 


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Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 20179 

penalties are ‘appropriate’ in a given 

private civil suit is a job for the courts, 

not EPA.’’). The EPA is finalizing the 

proposed removal of the regulatory 

affirmative defense provision from 

MATS. In the event that a source fails 

to comply with an applicable CAA 

section 112(d) standard as a result of a 

malfunction event, the EPA’s ability to 

exercise its case-by-case-enforcement 

discretion to determine an appropriate 

response provides sufficient flexibility 

in such circumstances as was explained 

in the preamble to the proposed rule. 

Further, as the D.C. Circuit recognized, 

in an EPA or citizen enforcement action, 

the court has the discretion to consider 

any defense raised and determine 

whether penalties are appropriate. Cf. 

NRDC, 2014 U.S. App. LEXIS 7281 at 

*24 (arguments that violation were 

caused by unavoidable technology 

failure can be made to the courts in 

future civil cases when the issue arises). 

The same is true for the presiding officer 

in EPA administrative enforcement 

actions. For all these reasons, this final 

rule removes the affirmative defense 

provisions. 

V. Impacts of This Final Rule 

This action finalizes certain 

provisions and makes technical and 

clarifying corrections, but does not 

promulgate substantive changes to the 

February 2012 final MATS (77 FR 9304). 

Therefore, there are no environmental, 

energy, or economic impacts associated 

with this final action. The impacts 

associated with MATS are discussed in 

detail in the February 16, 2012, final 

MATS rule. 

VI. Statutory and Executive Order 

Reviews 

Additional information about these 

statutes and Executive Orders can be 

found at http://www2.epa.gov/lawsregulations/laws-and-executive-orders. 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is not a significant 

regulatory action and was, therefore, not 

submitted to the Office of Management 

and Budget (OMB) for review. 

B. Paperwork Reduction Act (PRA) 

This action does not impose any new 

information collection burden under the 

PRA. OMB has previously approved the 

information collection activities 

contained in the existing regulations (40 

CFR part 63, subpart UUUUU) and has 

assigned OMB control number 2060– 

0567. This action is believed to result in 

no changes to the ICR of the February 

2012 final MATS rule, so that the 

information collection estimate of 

project cost and hour burden from the 

final MATS have not been revised. 

C. Regulatory Flexibility Act (RFA) 

I certify that this action will not have 

a significant economic impact on a 

substantial number of small entities 

under the RFA. This action will not 

impose any requirements on small 

entities. This action finalizes changes to 

MATS to correct and clarify 

implementation issues raised by 

stakeholders. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This action does not contain an 

unfunded mandate as described in 

UMRA, 2 U.S.C. 1531–1538, and does 

not significantly or uniquely affect small 

governments. This rule promulgates 

amendments to the February 2012 final 

MATS, but the amendments are 

clarifications to existing rule language to 

aid in implementation. Therefore, the 

action imposes no enforceable duty on 

any state, local, or tribal governments or 

the private sector. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175. It 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, as 

specified in Executive Order 13175. 

This action clarifies certain components 

of the February 2012 final MATS. Thus, 

Executive Order 13175 does not apply 

to this action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

The EPA interprets Executive Order 

13045 as applying only to those 

regulatory actions that concern 

environmental health or safety risks that 

the EPA has reason to believe may 

disproportionately affect children, per 

the definition of ‘‘covered regulatory 

action’’ in section 2–202 of the 

Executive Order. This action is not 

subject to Executive Order 13045 

because it does not concern an 

environmental health risk or safety risk. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution or Use 

This action is not subject to Executive 

Order 13211 because it is not a 

significant regulatory action under 

Executive Order 12866. 

I. National Technology Transfer and 

Advancement Act (NTTAA) 

This action does not involve technical 

standards from those contained in the 

February 16, 2012, final rule. Therefore, 

the EPA did not consider the use of any 

voluntary consensus standards. See 77 

FR 9441–9443 for the NTTAA 

discussion in the February 16, 2012, 

final rule. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

The EPA believes the human health or 

environmental risk addressed by this 

action will not have potential 

disproportionately high and adverse 

human health or environmental effects 

on minority, low-income, or indigenous 

populations because it does not affect 

the level of protection provided to 

human health or the environment. 

The environmental justice finding in 

the February 2012 final MATS remains 

relevant in this action, which finalizes 

changes to the rule to correct and clarify 

implementation issues raised by 

stakeholders. 

K. Congressional Review Act (CRA) 

This action is subject to the CRA, and 

the EPA will submit a rule report to 

each House of the Congress and to the 

Comptroller General of the United 

States. This action is not a ‘‘major rule’’ 

as defined by 5 U.S.C. 804(2). 

List of Subjects 

40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Intergovernmental 

relations, Reporting and recordkeeping 

requirements. 

40 CFR Part 63 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Hazardous 

substances, Intergovernmental relations, 

Reporting and recordkeeping 

requirements. 


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20180 Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 

Dated: March 17, 2016. 

Gina McCarthy, 

Administrator. 

For the reasons discussed in the 

preamble, the EPA amends 40 CFR parts 

60 and 63 as follows: 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

■ 1. The authority citation for part 60 

continues to read as follows: 

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

■ 2. Section 60.48Da is amended by 

revising paragraph (f) to read as follows: 

§ 60.48Da Compliance provisions. 

* * * * * 

(f) For affected facilities for which 

construction, modification, or 

reconstruction commenced before May 

4, 2011, compliance with the applicable 

daily average PM emissions limit is 

determined by calculating the 

arithmetic average of all hourly 

emission rates each boiler operating 

day, except for data obtained during 

startup, shutdown, or malfunction 

periods. Daily averages are only 

calculated for boiler operating days that 

have non-out-of-control data for at least 

18 hours of unit operation during which 

the standard applies. Instead, all of the 

non-out-of-control hourly emission rates 

of the operating day(s) not meeting the 

minimum 18 hours non-out-of-control 

data daily average requirement are 

averaged with all of the non-out-ofcontrol hourly emission rates of the next 

boiler operating day with 18 hours or 

more of non-out-of-control PM CEMS 

data to determine compliance. For 

affected facilities for which construction 

or reconstruction commenced after May 

3, 2011 that elect to demonstrate 

compliance using PM CEMS, 

compliance with the applicable PM 

emissions limit in § 60.42Da is 

determined on a 30-boiler operating day 

rolling average basis by calculating the 

arithmetic average of all hourly PM 

emission rates for the 30 successive 

boiler operating days, except for data 

obtained during periods of startup and 

shutdown. 

* * * * * 

PART 63—NATIONAL EMISSION 

STANDARDS FOR HAZARDOUS AIR 

POLLUTANTS FOR SOURCE 

CATEGORIES 

■ 3. The authority citation for part 63 

continues to read as follows: 

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

■ 4. Section 63.9983 is amended by: 

■ a. Revising the section heading and 

paragraphs (a), (b), and (c); and 

■ b. Adding paragraph (e). 

The revisions and addition read as 

follows: 

§ 63.9983 Are any fossil fuel-fired electric 

generating units not subject to this 

subpart? 

* * * * * 

(a) Any unit designated as a major 

source stationary combustion turbine 

subject to subpart YYYY of this part and 

any unit designated as an area source 

stationary combustion turbine, other 

than an integrated gasification 

combined cycle (IGCC) unit. 

(b) Any electric utility steam 

generating unit that is not a coal- or oilfired EGU and that meets the definition 

of a natural gas-fired EGU in § 63.10042. 

(c) Any electric utility steam 

generating unit that has the capability of 

combusting more than 25 MW of coal or 

oil but does not meet the definition of 

a coal- or oil-fired EGU because it did 

not fire sufficient coal or oil to satisfy 

the average annual heat input 

requirement set forth in the definitions 

for coal-fired and oil-fired EGUs in 

§ 63.10042. Heat input means heat 

derived from combustion of fuel in an 

EGU 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 industrial boilers). 

* * * * * 

(e) Any electric utility steam 

generating unit that meets the definition 

of a natural gas-fired EGU under this 

subpart and that fires at least 10 percent 

biomass is an industrial boiler subject to 

standards established under subpart 

DDDDD of this part, if it otherwise 

meets the applicability provisions in 

that rule. 

■ 5. Section 63.9991 is amended by 

revising paragraphs (c)(1) and (2) to read 

as follows: 

§ 63.9991 What emission limitations, work 

practice standards, and operating limits 

must I meet? 

* * * * * 

(c) * * * 

(1) Has a system using wet or dry flue 

gas desulfurization technology and an 

SO2 continuous emissions monitoring 

system (CEMS) installed on the EGU; 

and 

(2) At all times, you operate the wet 

or dry flue gas desulfurization 

technology and the SO2 CEMS installed 

on the EGU consistent with 

§ 63.10000(b). 

■ 6. Section 63.10000 is amended by 

revising paragraphs (a), (c)(1)(i), 

(c)(2)(iii), (f), (g), and (i)(1) and adding 

paragraphs (m) and (n) to read as 

follows: 

§ 63.10000 What are my general 

requirements for complying with this 

subpart? 

(a) You must be in compliance with 

the emission limits and operating limits 

in this subpart. These limits apply to 

you at all times except during periods 

of startup and shutdown; however, for 

coal-fired, liquid oil-fired, or solid oilderived fuel-fired EGUs, you are 

required to meet the work practice 

requirements, items 3 and 4, in Table 3 

to this subpart during periods of startup 

or shutdown. 

* * * * * 

(c)(1) * * * 

(i) For a coal-fired or solid oil-derived 

fuel-fired EGU or IGCC EGU, you may 

conduct initial performance testing in 

accordance with § 63.10005(h), to 

determine whether the EGU qualifies as 

a low emitting EGU (LEE) for one or 

more applicable emission limits, except 

as otherwise provided in paragraphs 

(c)(1)(i)(A) and (B) of this section: 

(A) Except as provided in paragraph 

(c)(1)(i)(C) of this section, you may not 

pursue the LEE option if your coal-fired, 

IGCC, or solid oil-derived fuel-fired 

EGU is equipped with a main stack and 

a bypass stack or bypass duct 

configuration that allows the effluent to 

bypass any pollutant control device. 

(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. 

(C) You may pursue the LEE option 

provided that: 

(1) Your EGU’s control device bypass 

emissions are measured in the bypass 

stack or duct or your control device 

bypass exhaust is routed through the 

EGU main stack so that emissions are 

measured during the bypass event; or 

(2) Except for hours during which 

only clean fuel is combusted, you 

bypass your EGU control device only 

during emergency periods for no more 

than a total of 2 percent of your EGU’s 

annual operating hours; you use clean 

fuels to the maximum extent possible 

during an emergency period; and you 

prepare and submit a report describing 

the emergency event, its cause, 

corrective action taken, and estimates of 

emissions released during the 

emergency event. You must include 

these emergency emissions along with 

performance test results in assessing 

whether your EGU maintains LEE 

status. 

* * * * * 

(2) * * * 


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(iii) If your existing liquid oil-fired 

unit does not qualify as a LEE for 

hydrogen chloride (HCl) or for hydrogen 

fluoride (HF), you may demonstrate 

initial and continuous compliance 

through use of an HCl CEMS, an HF 

CEMS, or an HCl and HF CEMS, 

installed and operated in accordance 

with Appendix B to this rule. As an 

alternative to HCl CEMS, HF CEMS, or 

HCl and HF CEMS, you may 

demonstrate initial and continuous 

compliance through quarterly 

performance testing and parametric 

monitoring for HCl and HF. If you 

choose to use quarterly testing and 

parametric monitoring, then you must 

also develop a site-specific monitoring 

plan that identifies the CMS you will 

use to ensure that the operations of the 

EGU remains consistent with those 

during the performance test. As another 

alternative, you may measure or obtain, 

and keep records of, fuel moisture 

content; as long as fuel moisture does 

not exceed 1.0 percent by weight, you 

need not conduct other HCl or HF 

monitoring or testing. 

* * * * * 

(f) Except as provided under 

paragraph (n) of this section, 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 distributions 

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 your unit is 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. 

(g) Except as provided under 

paragraph (n) of this section, if your unit 

no longer meets the definition of an 

EGU subject to this subpart you must be 

in compliance with any newly 

applicable standards on the date you are 

no longer subject to this subpart. The 

date you are no longer subject to this 

subpart is a date selected by you, that 

must be at least 6 months from the date 

that your unit last met the definition of 

an EGU subject to this subpart or the 

date you begin combusting solid waste, 

consistent with § 63.9983(d). Your 

source must remain in compliance with 

this subpart until the date you select to 

cease complying with this subpart or the 

date you begin combusting solid waste, 

whichever is earlier. 

* * * * * 

(i)(1) If you own or operate an EGU 

subject to this subpart and cease to 

operate in a manner that causes your 

unit to meet the definition of an EGU 

subject to this subpart, you must be in 

compliance with any newly applicable 

section 112 or 129 standards on the date 

you selected consistent with paragraphs 

(g) and (n) of this section. 

* * * * * 

(m) Should you choose to rely on 

paragraph (2) of the definition of 

‘‘startup’’ in § 63.10042 for your EGU, 

on or before the date your EGU is 

subject to this subpart, you must install, 

verify, operate, maintain, and quality 

assure each monitoring system 

necessary for demonstrating compliance 

with the work practice standards for PM 

or non-mercury HAP metals controls 

during startup periods and shutdown 

periods required to comply with 

§ 63.10020(e). 

(1) You may rely on monitoring 

system specifications or instructions or 

manufacturer’s specifications when 

installing, verifying, operating, 

maintaining, and quality assuring each 

monitoring system. 

(2) You must collect, record, report, 

and maintain data obtained from these 

monitoring systems during startup 

periods and shutdown periods. 

(n) If you have permanently converted 

your EGU from coal or oil to natural gas 

or biomass after your compliance date 

(or, if applicable, after your approved 

extended compliance date), as 

demonstrated by being subject to a 

permit provision or physical limitation 

(including retirement) that prevents you 

from operating in a manner that would 

subject you to this subpart, you are no 

longer subject to this subpart, 

notwithstanding the coal or oil usage in 

the previous calendar years. The date on 

which you are no longer subject to this 

subpart is the date on which you 

converted to natural gas or biomass 

firing; it is also the date on which you 

must be in compliance with any newly 

applicable standards. 

§ 63.10001 [Removed and Reserved] 

■ 7. Section 63.10001 is removed and 

reserved. 

■ 8. Section 63.10005 is amended by: 

■ a. Revising paragraphs (a) 

introductory text, (a)(2) introductory 

text, (a)(2)(i) and (ii), and (b)(4); 

■ b. Adding paragraph (b)(6); 

■ c. Revising paragraphs (d)(3), (d)(4)(i), 

(f), (h) introductory text, (h)(3) 

introductory text, (h)(3)(i)(D), and 

(h)(3)(iii) introductory text; and 

■ d. Removing paragraphs (i)(4)(iii) and 

(iv). 

The revisions and additions read as 

follows: 

§ 63.10005 What are my initial compliance 

requirements and by what date must I 

conduct them? 

(a) General requirements. For each of 

your affected EGUs, you must 

demonstrate initial compliance with 

each applicable emissions limit in Table 

1 or 2 of this subpart through 

performance testing. Where two 

emissions limits are specified for a 

particular pollutant (e.g., a heat inputbased limit in lb/MMBtu and a gross 

output-based limit in lb/MWh), you may 

demonstrate compliance with either 

emission limit. For a particular 

compliance demonstration, you may be 

required to conduct one or more of the 

following activities in conjunction with 

performance testing: collection of data, 

e.g., hourly gross output data 

(megawatts); establishment of operating 

limits according to § 63.10011 and 

Tables 4 and 7 to this subpart; and CMS 

performance evaluations. In all cases, 

you must demonstrate initial 

compliance no later than the date in 

paragraph (f) of this section for tune-up 

work practices for existing EGUs; the 

date that compliance must be 

demonstrated, as given in § 63.9984 for 

other requirements for existing EGUs; 

and in paragraph (g) of this section for 

all requirements for new EGUs. 

* * * * * 

(2) To demonstrate initial compliance 

using either a CMS that measures HAP 

concentrations directly (i.e., an Hg, HCl, 

or HF CEMS, or a sorbent trap 

monitoring system) or an SO2 or PM 

CEMS, the initial performance test shall 

consist of 30- or, for certain coal-fired 

existing EGUs that use emissions 

averaging for Hg, 90-boiler operating 

days. If the CMS is certified prior to the 

compliance date (or, if applicable, the 

approved extended compliance date), 

the test shall begin with the first 

operating day on or after that date, 

except as otherwise provided in 

paragraph (b) of this section. If the CMS 

is not certified prior to the compliance 


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date, the test shall begin with the first 

operating day after certification testing 

is successfully completed. In all cases, 

the initial 30- or 90- operating day 

averaging period must be completed on 

or before the date that compliance must 

be demonstrated (i.e., 180 days after the 

applicable compliance date). 

(i) The CMS performance test must 

demonstrate compliance with the 

applicable Hg, HCl, HF, PM, or SO2

emissions limit in Table 1 or 2 to this 

subpart. 

(ii) You must collect hourly data from 

auxiliary monitoring systems (i.e., stack 

gas flow rate, CO2, O2, or moisture, as 

applicable) during the performance test 

period, in order to convert the pollutant 

concentrations to units of the standard. 

If you choose to comply with a gross 

output-based emission limit, you must 

also collect hourly gross output data 

during the performance test period. 

* * * * * 

(b) * * * 

(4) A record of all parameters needed 

to convert pollutant concentrations to 

units of the emission standard (e.g., 

stack flow rate, diluent gas 

concentrations, hourly gross outputs) is 

available for the entire performance test 

period; and 

* * * * * 

(6) For performance stack test data 

that are collected prior to the date that 

compliance must be demonstrated and 

are used to demonstrate initial 

compliance with applicable emissions 

limits, the interval for subsequent stack 

tests begins on the date that compliance 

must be demonstrated. 

* * * * * 

(d) * * * 

(3) For affected EGUs that are either 

required to or elect to demonstrate 

initial compliance with the applicable 

Hg emission limit in Table 1 or 2 of this 

subpart using Hg CEMS or sorbent trap 

monitoring systems, initial compliance 

must be demonstrated no later than the 

applicable date specified in § 63.9984(f) 

for existing EGUs and in paragraph (g) 

of this section for new EGUs. Initial 

compliance is achieved if the arithmetic 

average of 30- (or 90-) boiler operating 

days of quality-assured CEMS (or 

sorbent trap monitoring system) data, 

expressed in units of the standard (see 

section 6.2 of appendix A to this 

subpart), meets the applicable Hg 

emission limit in Table 1 or 2 to this 

subpart. 

(4) * * * 

(i) You must demonstrate initial 

compliance no later than the applicable 

date specified in § 63.9984(f) for existing 

EGUs and in paragraph (g) of this 

section for new EGUs. 

* * * * * 

(f) For an existing EGU without a 

neural network, a tune-up, following the 

procedures in § 63.10021(e), must occur 

within 6 months (180 days) after April 

16, 2015. For an existing EGU with a 

neural network, a tune-up must occur 

within 18 months (545 days) after April 

16, 2016. If a tune-up occurs prior to 

April 16, 2015, you must keep records 

showing that the tune-up met all rule 

requirements. 

* * * * * 

(h) Low emitting EGUs. The 

provisions of this paragraph (h) apply to 

pollutants with emissions limits from 

new EGUs except Hg and to all 

pollutants with emissions limits from 

existing EGUs. You may pursue this 

compliance option unless prohibited 

pursuant to § 63.10000(c)(1)(i). 

* * * * * 

(3) For Hg, you must conduct a 30- (or 

90-) boiler operating day performance 

test using Method 30B in appendix A– 

8 to part 60 of this chapter to determine 

whether a unit qualifies for LEE status. 

Locate the Method 30B sampling probe 

tip at a point within 10 percent of the 

duct area centered about the duct’s 

centroid at a location that meets Method 

1 in appendix A–1 to part 60 of this 

chapter and conduct at least three 

nominally equal length test runs over 

the 30- (or 90-) boiler operating day test 

period. You may use a pair of sorbent 

traps to sample the stack gas for a period 

consistent with that given in section 

5.2.1 of appendix A to this subpart. 

Collect Hg emissions data continuously 

over the entire test period (except when 

changing sorbent traps or performing 

required reference method QA 

procedures). As an alternative to 

constant rate sampling per Method 30B, 

you may use proportional sampling per 

section 8.2.2 of Performance 

Specification 12 B in appendix B to part 

60 of this chapter. 

(i) * * * 

(D) Hourly gross output data 

(megawatts), from facility records. 

* * * * * 

(iii) Calculate the average Hg 

concentration, in mg/m3 (dry basis), for 

the 30- (or 90-) boiler operating day 

performance test, as the arithmetic 

average of all Method 30B sorbent trap 

results. Also calculate, as applicable, the 

average values of CO2 or O2

concentration, stack gas flow rate, stack 

gas moisture content, and gross output 

for the test period. Then: 

* * * * * 

■ 9. Section 63.10006 is amended by 

revising paragraph (f) and removing 

paragraph (j) to read as follows: 

§ 63.10006 When must I conduct 

subsequent performance tests or tune-ups? 

* * * * * 

(f) Time between performance tests. 

(1) Notwithstanding the provisions of 

§ 63.10021(d)(1), the requirements listed 

in paragraphs (g) and (h) of this section, 

and the requirements of paragraph (f)(3) 

of this section, you must complete 

performance tests for your EGU as 

follows: 

(i) At least 45 calendar days, 

measured from the test’s end date, must 

separate performance tests conducted 

every quarter; 

(ii) For annual testing: 

(A) At least 320 calendar days, 

measured from the test’s end date, must 

separate performance tests; 

(B) At least 320 calendar days, 

measured from the test’s end date, must 

separate annual sorbent trap mercury 

testing for 30-boiler operating day LEE 

tests; 

(C) At least 230 calendar days, 

measured from the test’s end date, must 

separate annual sorbent trap mercury 

testing for 90-boiler operating day LEE 

tests; and 

(iii) At least 1,050 calendar days, 

measured from the test’s end date, must 

separate performance tests conducted 

every 3 years. 

(2) For units demonstrating 

compliance through quarterly emission 

testing, you must conduct a 

performance test in the 4th quarter of a 

calendar year if your EGU has skipped 

performance tests in the first 3 quarters 

of the calendar year. 

(3) If your EGU misses a performance 

test deadline due to being inoperative 

and if 168 or more boiler operating 

hours occur in the next test period, you 

must complete an additional 

performance test in that period as 

follows: 

(i) At least 15 calendar days must 

separate two performance tests 

conducted in the same quarter. 

(ii) At least 107 calendar days must 

separate two performance tests 

conducted in the same calendar year. 

(iii) At least 350 calendar days must 

separate two performance tests 

conducted in the same 3 year period. 

* * * * * 

■ 10. Section 63.10007 is amended by 

revising paragraph (f)(2) to read as 

follows: 

§ 63.10007 What methods and other 

procedures must I use for the performance 

tests? 

* * * * * 


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(f) * * * 

(2) Default gross output. If you use 

CEMS to continuously monitor Hg, HCl, 

HF, SO2, or PM emissions (or, if 

applicable, sorbent trap monitoring 

systems to continuously collect Hg 

emissions data), the following default 

value is available for use in the emission 

rate calculations during startup periods 

or shutdown periods (as defined in 

§ 63.10042). For the purposes of this 

subpart, this default value is not 

considered to be substitute data. For a 

startup or shutdown hour in which 

there is heat input to an affected EGU 

but zero gross output, you must 

calculate the pollutant emission rate 

using a value equivalent to 5% of the 

maximum sustainable gross output, 

expressed in megawatts, as defined in 

section 6.5.2.1(a)(1) of appendix A to 

part 75 of this chapter. This default 

gross output is either the nameplate 

capacity of the EGU or the highest gross 

output observed in at least four 

representative quarters of EGU 

operation. For a monitored common 

stack, the default gross output is used 

only when all EGUs are operating (i.e., 

combusting fuel) are in startup or 

shutdown mode, and have zero 

electrical generation. Under those 

conditions, a default gross output equal 

to 5% of the combined maximum 

sustainable gross output of the EGUs 

that are operating but have a total of 

zero gross output must be used to 

calculate the hourly gross output-based 

pollutant emissions rate. 

* * * * * 

■ 11. Section 63.10009 is amended by 

revising paragraphs (a)(2) introductory 

text, (a)(2)(i), (b)(1) through (3), (e), (f) 

introductory text, (f)(2), (g), (j)(1)(ii), and 

(j)(2) introductory text to read as 

follows: 

§ 63.10009 May I use emissions averaging 

to comply with this subpart? 

(a) * * * 

(2) You may demonstrate compliance 

by emissions averaging among the 

existing EGUs in the same subcategory, 

if your averaged Hg emissions for EGUs 

in the ‘‘unit designed for coal ≥8,300 

Btu/lb’’ subcategory are equal to or less 

than 1.2 lb/TBtu or 1.3E–2 lb/GWh on 

a 30-boiler operating day basis or if your 

averaged emissions of individual, other 

pollutants from other subcategories of 

such EGUs are equal to or less than the 

applicable emissions limit in Table 2 to 

this subpart, according to the 

procedures in this section. Note that 

except for the alternate Hg emissions 

limit from EGUs in the ‘‘unit designed 

for coal ≥ 8,300 Btu/lb’’ subcategory, the 

averaging time for emissions averaging 

for pollutants is 30 days (rolling daily) 

using data from CEMS or a combination 

of data from CEMS and manual 

performance (LEE) testing. The 

averaging time for emissions averaging 

for the alternate Hg limit (equal to or 

less than 1.0 lb/TBtu or 1.1E–2 lb/GWh) 

from EGUs in the ‘‘unit designed for 

coal ≥ 8,300 Btu/lb’’ subcategory is 90- 

boiler operating days (rolling daily) 

using data from CEMS, sorbent trap 

monitoring, or a combination of 

monitoring data and data from manual 

performance (LEE) testing. For the 

purposes of this paragraph, 30- 

(or 90-) group boiler operating days is 

defined as a period during which at 

least one unit in the emissions averaging 

group operates on each of the 30 or 90 

days. You must calculate the weighted 

average emissions rate for the group in 

accordance with the procedures in this 

paragraph using the data from all units 

in the group including any that operate 

fewer than 30 (or 90) days during the 

preceding 30 (or 90) group boiler days. 

(i) You may choose to have your EGU 

emissions averaging group meet either 

the heat input basis (MMBtu or TBtu, as 

appropriate for the pollutant) or gross 

output basis (MWh or GWh, as 

appropriate for the pollutant). 

* * * * * 

(b) * * * 

(1) Group eligibility equations. 

Where: 

WAERm = Maximum Weighted Average 

Emission Rate in terms of lb/heat input 

or lb/gross output, 

Hermi,j = hourly emission rate (e.g., lb/

MMBtu, lb/MWh) from CEMS or sorbent 

trap monitoring as determined during the 

initial compliance determination from 

EGU j, 

Rmmj = Maximum rated heat input, 

MMBtu/h, or maximum rated gross output, 

MWh/h, for EGU j, 

p = number of EGUs in emissions averaging 

group that rely on CEMS, 

Terk = Emissions rate (lb/MMBTU or lb/

MWh) as determined during the initial 

compliance determination of EGU k, 

Rmtk = Maximum rated heat input, 

MMBtu/h, or maximum rated gross output, 

MWh/h, for EGU k, and 

m = number of EGUs in emissions averaging 

group that rely on emissions testing. 

Where: 

Variables with the similar names share the 

descriptions for Equation 1a of this section, 

Smmj = maximum steam generation, 

lbsteam/h or lb/gross output, for EGU j, 

Cfmj = conversion factor, calculated from the 

most recent compliance test results, in 

terms units of heat output or gross output 

per pound of steam generated (MMBtu/

lbsteam or MWh/lbsteam) from EGU j, 

Smtk = maximum steam generation, lbsteam/h 

or lb/gross output, for EGU k, and 

Cfmk = conversion factor, calculated from the 

most recent compliance test results, in 

terms units of heat output or gross output 

per pound of steam generated (MMBtu/

lbsteam or MWh/lbsteam) from EGU k. 

(2) Weighted 30-boiler operating day 

rolling average emissions rate equations for 

pollutants other than Hg. Use Equation 2a or 

2b of this section to calculate the 30 day 

rolling average emissions daily. 


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Where: 

Heri = hourly emission rate (e.g., lb/MMBtu, 

lb/MWh) from unit i’s CEMS for the 

preceding 30-group boiler operating days, 

Rmi = hourly heat input or gross output from 

unit i for the preceding 30-group boiler 

operating days, 

p = number of EGUs in emissions averaging 

group that rely on CEMS or sorbent trap 

monitoring, 

n = number of hours that hourly rates are 

collected over 30-group boiler operating 

days, 

Teri = Emissions rate from most recent 

emissions test of unit i in terms of lb/

heat input or lb/gross output, 

Rti = Total heat input or gross output of unit 

i for the preceding 30-boiler operating 

days, and 

m = number of EGUs in emissions averaging 

group that rely on emissions testing. 

Where: 

variables with similar names share the 

descriptions for Equation 2a of this 

section, 

Smi = steam generation in units of pounds 

from unit i that uses CEMS for the 

preceding 30-group boiler operating 

days, 

Cfmi = conversion factor, calculated from the 

most recent compliance test results, in 

units of heat input per pound of steam 

generated or gross output per pound of 

steam generated, from unit i that uses 

CEMS from the preceding 30 group 

boiler operating days, 

Sti = steam generation in units of pounds 

from unit i that uses emissions testing, 

and 

Cfti = conversion factor, calculated from the 

most recent compliance test results, in 

units of heat input per pound of steam 

generated or gross output per pound of 

steam generated, from unit i that uses 

emissions testing. 

(3) Weighted 90-boiler operating day 

rolling average emissions rate equations for 

Hg emissions from EGUs in the ‘‘coal-fired 

unit not low rank virgin coal’’ subcategory. 

Use Equation 3a or 3b of this section to 

calculate the 90-day rolling average 

emissions daily. 

Where: 

Heri = hourly emission rate from unit i’s 

CEMS or Hg sorbent trap monitoring 

system for the preceding 90-group boiler 

operating days, 

Rmi = hourly heat input or gross output from 

unit i for the preceding 90-group boiler 

operating days, 

p = number of EGUs in emissions averaging 

group that rely on CEMS, 

n = number of hours that hourly rates are 

collected over the 90-group boiler 

operating days, 

Teri = Emissions rate from most recent 

emissions test of unit i in terms of lb/

heat input or lb/gross output, 

Rti = Total heat input or gross output of unit 

i for the preceding 90-boiler operating 

days, and 

m = number of EGUs in emissions averaging 

group that rely on emissions testing. 

Where: 

variables with similar names share the 

descriptions for Equation 2a of this 

section, 

Smi = steam generation in units of pounds 

from unit i that uses CEMS or a Hg 

sorbent trap monitoring for the preceding 

90-group boiler operating days, 

Cfmi = conversion factor, calculated from the 

most recent compliance test results, in 

units of heat input per pound of steam 

generated or gross output per pound of 

steam generated, from unit i that uses 

CEMS or sorbent trap monitoring from 

the preceding 90-group boiler operating 

days, 

Sti = steam generation in units of pounds 

from unit i that uses emissions testing, 

and 

Cfti = conversion factor, calculated from the 

most recent emissions test results, in 

units of heat input per pound of steam 

generated or gross output per pound of 

steam generated, from unit i that uses 

emissions testing. 

* * * * * 

(e) The weighted-average emissions 

rate from the existing EGUs 

participating in the emissions averaging 

option must be in compliance with the 

limits in Table 2 to this subpart at all 

times following the date that you begin 

emissions averaging. 

(f) Emissions averaging group 

eligibility demonstration. You must 

demonstrate the ability for the EGUs 

included in the emissions averaging 

group to demonstrate initial compliance 

according to paragraph (f)(1) or (2) of 

this section using the maximum rated 

heat input or gross output over a 30- (or 

90-) boiler operating day period of each 

EGU and the results of the initial 

performance tests. For this 

demonstration and prior to preparing 

your emissions averaging plan, you 

must conduct required emissions 

monitoring for 30- (or 90-) days of boiler 

operation and any required manual 

performance testing to calculate 

maximum weighted average emissions 

rate in accordance with this section. If, 

before the start of your initial 

compliance demonstration, the 

Administrator becomes aware that you 

intend to use emissions averaging for 

that demonstration, or if your initial 

Notification of Compliance Status 

(NOCS) indicates that you intend to 


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Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 20185 

implement emissions averaging at a 

future date, the Administrator may 

require you to submit your proposed 

emissions averaging plan and 

supporting data for approval. If the 

Administrator requires approval of your 

plan, you may not begin using 

emissions averaging until the 

Administrator approves your plan. 

* * * * * 

(2) If you are not capable of 

monitoring heat input or gross output, 

and the EGU generates steam for 

purposes other than generating 

electricity, you may use Equation 1b of 

paragraph (b) of this section as an 

alternative to using Equation 1a of 

paragraph (b) of this section to 

demonstrate that the maximum 

weighted average emissions rates of 

filterable PM, HF, SO2, HCl, non-Hg 

HAP metals, or Hg emissions from the 

existing units participating in the 

emissions averaging group do not 

exceed the emission limits in Table 2 to 

this subpart. 

(g) You must determine the weighted 

average emissions rate in units of the 

applicable emissions limit on a 30 group 

boiler operating day rolling average 

basis (or, if applicable, on a 90 group 

boiler operating day rolling average 

basis for Hg) according to paragraphs 

(g)(1) and (2) of this section. The first 

averaging period ends on the 30th (or, 

if applicable, 90th for the alternate Hg 

emission limit) group boiler operating 

day after the date that you begin 

emissions averaging. 

(1) You must use Equation 2a or 3a of 

paragraph (b) of this section to calculate 

the weighted average emissions rate 

using the actual heat input or gross 

output for each existing unit 

participating in the emissions averaging 

option. 

(2) If you are not capable of 

monitoring heat input or gross output, 

you may use Equation 2b or 3b of 

paragraph (b) of this section as an 

alternative to using Equation 2a of 

paragraph (b) of this section to calculate 

the average weighted emission rate 

using the actual steam generation from 

the units participating in the emissions 

averaging option. 

* * * * * 

(j) * * * 

(1) * * * 

(ii) The process weighting parameter 

(heat input, gross output, or steam 

generated) that will be monitored for 

each averaging group; 

* * * * * 

(2) If, as described in paragraph (f) of 

this section, the Administrator requests 

you to submit the averaging plan for 

review and approval, you must receive 

approval before initiating emissions 

averaging. 

* * * * * 

■ 12. Section 63.10010 is amended by 

revising paragraphs (a)(4), (f)(3) and (4), 

(h)(6)(i) and (ii), (i)(5)(i)(A) and (B), 

(j)(1)(i), (j)(4)(i)(A) and (B), and (l) to 

read as follows: 

§ 63.10010 What are my monitoring, 

installation, operation, and maintenance 

requirements? 

(a) * * * 

(4) Unit with a main stack and a 

bypass stack that exhausts to the 

atmosphere independent of the main 

stack. If the exhaust configuration of an 

affected unit consists of a main stack 

and a bypass stack, you shall install 

CEMS on both the main stack and the 

bypass stack. If it is not feasible to 

certify and quality-assure the data from 

a monitoring system on the bypass 

stack, you shall: 

(i) Route the exhaust from the bypass 

through the main stack and its 

monitoring so that bypass emissions are 

measured; or 

(ii) Install a CEMS only on the main 

stack and count hours that the bypass 

stack is in use as hours of deviation 

from the monitoring requirements. 

* * * * * 

(f) * * * 

(3) Calculate and record a 30-boiler 

operating day rolling average SO2

emission rate in the units of the 

standard, updated after each new boiler 

operating day. Each 30-boiler operating 

day rolling average emission rate is the 

average of all of the valid hourly SO2

emission rates in the 30 boiler operating 

day period. 

(4) Use only unadjusted, qualityassured SO2 concentration values in the 

emissions calculations; do not apply 

bias adjustment factors to the part 75 

SO2 data and do not use part 75 

substitute data values. For startup or 

shutdown hours (as defined in 

§ 63.10042) the default gross output and 

the diluent cap are available for use in 

the hourly SO2 emission rate 

calculations, as described in 

§ 63.10007(f). Use a flag to identify each 

startup or shutdown hour and report a 

special code if the diluent cap or default 

gross output is used to calculate the SO2

emission rate for any of these hours. 

* * * * * 

(h) * * * 

(6) * * * 

(i) Any data collected during periods 

of monitoring system malfunctions, 

repairs associated with monitoring 

system malfunctions, or required 

monitoring system quality assurance or 

quality control activities that 

temporarily interrupt the measurement 

of output data from the PM CPMS. You 

must report any monitoring system 

malfunctions or out of control periods 

in your annual deviation reports. You 

must report any monitoring system 

quality assurance or quality control 

activities per the requirements of 

§ 63.10031(b); 

(ii) Any data collected during periods 

when the monitoring system is out of 

control as specified in your site-specific 

monitoring plan, repairs associated with 

periods when the monitoring system is 

out of control, or required monitoring 

system quality assurance or quality 

control activities conducted during outof-control periods. You must report any 

such periods in your annual deviation 

report; 

* * * * * 

(i) * * * 

(5) * * * 

(i) * * * 

(A) Any data collected during periods 

of monitoring system malfunctions, 

repairs associated with monitoring 

system malfunctions, or required 

monitoring system quality assurance or 

quality control activities that 

temporarily interrupt the measurement 

of emissions (e.g., calibrations, certain 

audits). You must report any monitoring 

system malfunctions or out of control 

periods in your annual deviation 

reports. You must report any monitoring 

system quality assurance or quality 

control activities per the requirements 

of § 63.10031(b); 

(B) Any data collected during periods 

when the monitoring system is out of 

control as specified in your site-specific 

monitoring plan, repairs associated with 

periods when the monitoring system is 

out of control, or required monitoring 

system quality assurance or quality 

control activities conducted during outof-control periods. You must report any 

such periods in your annual deviation 

report; 

* * * * * 

(j) * * * 

(1)(i) Install, calibrate, operate, and 

maintain your HAP metals CEMS 

according to your CMS quality control 

program, as described in § 63.8(d)(2). 

The reportable measurement output 

from the HAP metals CEMS must be 

expressed in units of the applicable 

emissions limit (e.g., lb/MMBtu, lb/

MWh) and in the form of a 30-boiler 

operating day rolling average. 

* * * * * 

(4) * * * 

(i) * * * 

(A) Any data collected during periods 

of monitoring system malfunctions, 

repairs associated with monitoring 


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system malfunctions, or required 

monitoring system quality assurance or 

quality control activities that 

temporarily interrupt the measurement 

of emissions (e.g., calibrations, certain 

audits). You must report any monitoring 

system malfunctions or out of control 

periods in your annual deviation 

reports. You must report any monitoring 

system quality assurance or quality 

control activities per the requirements 

of § 63.10031(b); 

(B) Any data collected during periods 

when the monitoring system is out of 

control as specified in your site-specific 

monitoring plan, repairs associated with 

periods when the monitoring system is 

out of control, or required monitoring 

system quality assurance or quality 

control activities conducted during outof-control periods. You must report any 

monitoring system malfunctions or out 

of control periods in your annual 

deviation reports. You must report any 

monitoring system quality assurance or 

quality control activities per the 

requirements of § 63.10031(b); 

* * * * * 

(l) Should you choose to rely on 

paragraph (2) of the definition of 

‘‘startup’’ in § 63.10042 for your EGU, 

you must install, verify, operate, 

maintain, and quality assure each 

monitoring system necessary for 

demonstrating compliance with the PM 

or non-mercury metals work practice 

standards required to comply with 

§ 63.10020(e). 

(1) You shall develop a site-specific 

monitoring plan for PM or non-mercury 

metals work practice monitoring during 

startup periods. 

(2) You shall submit the site-specific 

monitoring plan upon request by the 

Administrator. 

(3) The provisions of the monitoring 

plan must address the following items: 

(i) Monitoring system installation; 

(ii) Performance and equipment 

specifications; 

(iii) Schedule for initial and periodic 

performance evaluations; 

(iv) Performance evaluation 

procedures and acceptance criteria; 

(v) On-going operation and 

maintenance procedures; and 

(vi) On-going recordkeeping and 

reporting procedures. 

(4) You may rely on monitoring 

system specifications or instructions or 

manufacturer’s specifications to address 

paragraphs (l)(3)(i) through (vi) of this 

section. 

(5) You must operate and maintain 

the monitoring system according to the 

site-specific monitoring plan. 

■ 13. Section 63.10011 is amended by 

revising paragraphs (b), (c), (e), and (g) 

to read as follows: 

§ 63.10011 How do I demonstrate initial 

compliance with the emissions limits and 

work practice standards? 

* * * * * 

(b) If you are subject to an operating 

limit in Table 4 to this subpart, you 

demonstrate initial compliance with 

HAP metals or filterable PM emission 

limit(s) through performance stack tests 

and you elect to use a PM CPMS to 

demonstrate continuous performance, or 

if, for a liquid oil-fired EGU, and you 

use quarterly stack testing for HCl and 

HF plus site-specific parameter 

monitoring to demonstrate continuous 

performance, you must also establish a 

site-specific operating limit, in 

accordance with § 63.10007 and Table 6 

to this subpart. You may use only the 

parametric data recorded during 

successful performance tests (i.e., tests 

that demonstrate compliance with the 

applicable emissions limits) to establish 

an operating limit. 

(c)(1) If you use CEMS or sorbent trap 

monitoring systems to measure a HAP 

(e.g., Hg or HCl) directly, the initial 

performance test, shall consist of a 30- 

boiler operating day (or, for certain coalfired, existing EGUs that use emissions 

averaging for Hg, a 90-boiler operating 

day) rolling average emissions rate 

obtained with a certified CEMS or 

sorbent trap system, expressed in units 

of the standard. If the monitoring system 

is certified prior to the applicable 

compliance date, the initial averaging 

period shall either begin with: The first 

boiler operating day on or after the 

compliance date; or 30 (or, if applicable, 

90) boiler operating days prior to that 

date, as described in § 63.10005(b). In 

all cases, the initial 30- or 90-boiler 

operating day averaging period must be 

completed on or before the date that 

compliance must be demonstrated, in 

accordance with § 63.9984(f). Initial 

compliance is demonstrated if the 

results of the performance test meet the 

applicable emission limit in Table 1 or 

2 to this subpart. 

(2) For an EGU that uses a CEMS to 

measure SO2 or PM emissions for initial 

compliance, the initial performance test 

shall consist of a 30-boiler operating day 

average emission rate obtained with 

certified CEMS, expressed in units of 

the standard. If the monitoring system is 

certified prior to the applicable 

compliance date, the initial averaging 

period shall either begin with: The first 

boiler operating day on or after the 

compliance date; or 30 boiler operating 

days prior to that date, as described in 

§ 63.10005(b). In all cases, the initial 30- 

boiler operating day averaging period 

must be completed on or before the date 

that compliance must be demonstrated, 

in accordance with § 63.9984(f). Initial 

compliance is demonstrated if the 

results of the performance test meet the 

applicable SO2 or PM emission limit in 

Table 1 or 2 to this subpart. 

* * * * * 

(e) You must submit a Notification of 

Compliance Status containing the 

results of the initial compliance 

demonstration, in accordance with 

§ 63.10030(e). 

* * * * * 

(g) You must follow the startup or 

shutdown requirements as established 

in Table 3 to this subpart for each coalfired, liquid oil-fired, or solid oilderived fuel-fired EGU. 

(1) You may use the diluent cap and 

default gross output values, as described 

in § 63.10007(f), during startup periods 

or shutdown periods. 

(2) You must operate all CMS, collect 

data, calculate pollutant emission rates, 

and record data during startup periods 

or shutdown periods. 

(3) You must report the information as 

required in § 63.10031. 

(4) If you choose to use paragraph (2) 

of the definition of ‘‘startup’’ in 

§ 63.10042 and you find that you are 

unable to safely engage and operate your 

particulate matter (PM) control(s) within 

1 hour of first firing of coal, residual oil, 

or solid oil-derived fuel, you may 

choose to rely on paragraph (1) of 

definition of ‘‘startup’’ in § 63.10042 or 

you may submit a request to use an 

alternative non-opacity emissions 

standard, as described below. 

(i) As mentioned in § 63.6(g)(1), your 

request will be published in the Federal 

Register for notice and comment 

rulemaking. Until promulgation in the 

Federal Register of the final alternative 

non-opacity emission standard, you 

shall comply with paragraph (1) of the 

definition of ‘‘startup’’ in § 63.10042. 

You shall not implement the alternative 

non-opacity emissions standard until 

promulgation in the Federal Register of 

the final alternative non-opacity 

emission standard. 

(ii) Your request need not address the 

items contained in § 63.6(g)(2). 

(iii) Your request shall provide 

evidence of a documented 

manufacturer-identified safety issue. 

(iv) Your request shall provide 

information to document that the PM 

control device is adequately designed 

and sized to meet the PM emission limit 

applicable to the EGU. 

(v) In addition, your request shall 

contain documentation that: 

(A) Your EGU is using clean fuels to 

the maximum extent possible, taking 

into account considerations such as not 

compromising boiler or control device 

integrity, to bring your EGU and PM 


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control device up to the temperature 

necessary to alleviate or prevent the 

identified safety issues prior to the 

combustion of primary fuel in your 

EGU; 

(B) You have followed explicitly your 

EGU manufacturer’s procedures to 

alleviate or prevent the identified safety 

issue; and 

(C) You have identified with 

specificity the details of your EGU 

manufacturer’s statement of concern. 

(vi) Your request shall specify the 

other work practice standards you will 

take to limit HAP emissions during 

startup periods and shutdown periods 

to ensure a control level consistent with 

the work practice standards of the final 

rule. 

(vii) You must comply with all other 

work practice requirements, including 

but not limited to data collection, 

recordkeeping, and reporting 

requirements. 

■ 14. Section 63.10020 is amended by 

revising paragraph (e) to read as follows: 

§ 63.10020 How do I monitor and collect 

data to demonstrate continuous 

compliance? 

* * * * * 

(e) Additional requirements during 

startup periods or shutdown periods if 

you choose to rely on paragraph (2) of 

the definition of ‘‘startup’’ in § 63.10042 

for your EGU. 

(1) During each period of startup, you 

must record for each EGU: 

(i) The date and time that clean fuels 

being combusted for the purpose of 

startup begins; 

(ii) The quantity and heat input of 

clean fuel for each hour of startup; 

(iii) The gross output for each hour of 

startup; 

(iv) The date and time that non-clean 

fuel combustion begins; and 

(v) The date and time that clean fuels 

being combusted for the purpose of 

startup ends. 

(2) During each period of shutdown, 

you must record for each EGU: 

(i) The date and time that clean fuels 

being combusted for the purpose of 

shutdown begins; 

(ii) The quantity and heat input of 

clean fuel for each hour of shutdown; 

(iii) The gross output for each hour of 

shutdown; 

(iv) The date and time that non-clean 

fuel combustion ends; and 

(v) The date and time that clean fuels 

being combusted for the purpose of 

shutdown ends. 

(3) For PM or non-mercury HAP 

metals work practice monitoring during 

startup periods, you must monitor and 

collect data according to this section 

and the site-specific monitoring plan 

required by § 63.10010(l). 

(i) Except for an EGU that uses PM 

CEMS or PM CPMS to demonstrate 

compliance with the PM emissions 

limit, or that has LEE status for filterable 

PM or total non-Hg HAP metals for nonliquid oil-fired EGUs (or HAP metals 

emissions for liquid oil-fired EGUs), or 

individual non-mercury metals CEMS, 

you must: 

(A) Record temperature and 

combustion air flow or calculated flow 

as determined from combustion 

equations of post-combustion (exhaust) 

gas, as well as amperage of forced draft 

fan(s), upstream of the filterable PM 

control devices during each hour of 

startup. 

(B) Record temperature and flow of 

exhaust gas, as well as amperage of any 

induced draft fan(s), downstream of the 

filterable PM control devices during 

each hour of startup. 

(C) For an EGU with an electrostatic 

precipitator, record the number of fields 

in service, as well as each field’s 

secondary voltage and secondary 

current during each hour of startup. 

(D) For an EGU with a fabric filter, 

record the number of compartments in 

service, as well as the differential 

pressure across the baghouse during 

each hour of startup. 

(E) For an EGU with a wet scrubber 

needed for filterable PM control, record 

the scrubber liquid to flue gas ratio and 

the pressure drop across the scrubber 

during each hour of startup. 

(ii) [Reserved] 

■ 15. Section 63.10021 is amended by 

revising paragraphs (d)(3), (e) 

introductory text, (e)(9), and (h)(1) to 

read as follows: 

§ 63.10021 How do I demonstrate 

continuous compliance with the emission 

limitations, operating limits, and work 

practice standards? 

* * * * * 

(d) * * * 

(3) Must conduct site-specific 

monitoring using CMS to demonstrate 

compliance with the site-specific 

monitoring requirements in Table 7 to 

this subpart pertaining to HCl and HF 

emissions from a liquid oil-fired EGU to 

ensure compliance with the HCl and HF 

emission limits in Tables 1 and 2 to this 

subpart, in accordance with the 

requirements of § 63.10000(c)(2)(iii). 

The monitoring must meet the general 

operating requirements provided in 

§ 63.10020. 

(e) Conduct periodic performance 

tune-ups of your EGU(s), as specified in 

paragraphs (e)(1) through (9) of this 

section. For your first tune-up, you may 

perform the burner inspection any time 

prior to the tune-up or you may delay 

the first burner inspection until the next 

scheduled EGU outage provided you 

meet the requirements of § 63.10005. 

Subsequently, you must perform an 

inspection of the burner at least once 

every 36 calendar months unless your 

EGU employs neural network 

combustion optimization during normal 

operations in which case you must 

perform an inspection of the burner and 

combustion controls at least once every 

48 calendar months. If your EGU is 

offline when a deadline to perform the 

tune-up passes, you shall perform the 

tune-up work practice requirements 

within 30 days after the re-start of the 

affected unit. 

* * * * * 

(9) Report the dates of the initial and 

subsequent tune-ups in hard copy, as 

specified in § 63.10031(f)(5), until April 

16, 2017. After April 16, 2017, report 

the date of all tune-ups electronically, in 

accordance with § 63.10031(f). The 

tune-up report date is the date when 

tune-up requirements in paragraphs 

(e)(6) and (7) of this section are 

completed. 

* * * * * 

(h) * * * 

(1) You may use the diluent cap and 

default gross output values, as described 

in § 63.10007(f), during startup periods 

or shutdown periods. 

* * * * * 

■ 16. Section 63.10023 is amended by 

removing and reserving paragraph (b)(1) 

and revising paragraph (b)(2) 

introductory text to read as follows: 

§ 63.10023 How do I establish my PM 

CPMS operating limit and determine 

compliance with it? 

* * * * * 

(b) * * * 

(2) Determine your operating limit as 

follows: 

* * * * * 

■ 17. Section 63.10030 is amended by: 

■ a. Revising paragraphs (e)(1) and 

(e)(7)(i); 

■ b. Adding paragraph (e)(7)(iii); 

■ c. Revising paragraph (e)(8); and 

■ d. Adding paragraph (f). 

The revisions and additions read as 

follows: 

§ 63.10030 What notifications must I 

submit and when? 

* * * * * 

(e) * * * 

(1) A description of the affected 

source(s), including identification of the 

subcategory of the source, the design 

capacity of the source, a description of 

the add-on controls used on the source, 

description of the fuel(s) burned, 

including whether the fuel(s) were 

determined by you or EPA through a 


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petition process to be a non-waste under 

40 CFR 241.3, whether the fuel(s) were 

processed from discarded nonhazardous secondary materials within 

the meaning of 40 CFR 241.3, and 

justification for the selection of fuel(s) 

burned during the performance test. 

* * * * * 

(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 

§ 63.10005(h)(1)(i), the date of each 

stack test conducted during the previous 

3 years, a comparison of emission level 

you achieved in each stack test 

conducted during the previous 3 years 

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. 

* * * * * 

(iii) For each of your existing EGUs, 

identification of each emissions limit as 

specified in Table 2 to this subpart with 

which you plan to comply. 

(A) You may switch from a mass per 

heat input to a mass per gross output 

limit (or vice-versa), provided that: 

(1) You submit a request that 

identifies for each EGU or EGU 

emissions averaging group involved in 

the proposed switch both the current 

and proposed emission limit; 

(2) Your request arrives to the 

Administrator at least 30 calendar days 

prior to the date that the switch is 

proposed to occur; 

(3) Your request demonstrates through 

performance stack test results 

completed within 30 days prior to your 

submission, compliance for each EGU or 

EGU emissions averaging group with 

both the mass per heat input and mass 

per gross output limits; 

(4) You revise and submit all other 

applicable plans, e.g., monitoring and 

emissions averaging, with your request; 

and 

(5) You maintain records of all 

information regarding your choice of 

emission limits. 

(B) You begin to use the revised 

emission limits starting in the next 

reporting period, after receipt of written 

acknowledgement from the 

Administrator of the switch. 

(C) From submission of your request 

until start of the next reporting period 

after receipt of written 

acknowledgement from the 

Administrator of the switch, you 

demonstrate compliance with both the 

mass per heat input and mass per gross 

output emission limits for each 

pollutant for each EGU or EGU 

emissions averaging group. 

(8) Identification of whether you plan 

to rely on paragraph (1) or (2) of the 

definition of ‘‘startup’’ in § 63.10042. 

(i) Should you choose to rely on 

paragraph (2) of the definition of 

‘‘startup’’ in § 63.10042 for your EGU, 

you shall include a report that 

identifies: 

(A) The original EGU installation 

date; 

(B) The original EGU design 

characteristics, including, but not 

limited to, fuel mix and PM controls; 

(C) Each design PM control device 

efficiency established during 

performance testing or while operating 

in periods other than startup and 

shutdown periods; 

(D) The design PM emission rate from 

the EGU in terms of pounds PM per 

MMBtu and pounds PM per hour 

established during performance testing 

or while operating in periods other than 

startup and shutdown periods; 

(E) The design time from start of fuel 

combustion to necessary conditions for 

each PM control device startup; 

(F) Each design PM control device 

efficiency upon startup of the PM 

control device, if different from the 

efficiency provided in paragraph 

(e)(8)(i)(C) of this section; 

(G) Current EGU PM producing 

characteristics, including, but not 

limited to, fuel mix and PM controls, if 

different from the characteristics 

provided in paragraph (e)(8)(i)(B) of this 

section; 

(H) Current PM control device 

efficiency from each PM control device, 

if different from the efficiency provided 

in paragraph (e)(8)(i)(C) of this section; 

(I) Current PM emission rate from the 

EGU in terms of pounds PM per MMBtu 

and pounds per hour, if different from 

the rate provided in paragraph 

(e)(8)(i)(D) of this section; 

(J) Current time from start of fuel 

combustion to conditions necessary for 

each PM control device startup, if 

different from the time provided in 

paragraph (e)(8)(i)(E) of this section; and 

(K) Current PM control device 

efficiency upon startup of each PM 

control device, if different from the 

efficiency provided in paragraph 

(e)(8)(i)(H) of this section. 

(ii) The report shall be prepared, 

signed, and sealed by a professional 

engineer licensed in the state where 

your EGU is located. 

(iii) You may switch from paragraph 

(1) of the definition of ‘‘startup’’ in 

§ 63.10042 to paragraph (2) of the 

definition of ‘‘startup’’ (or vice-versa), 

provided that: 

(A) You submit a request that 

identifies for each EGU or EGU 

emissions averaging group involved in 

the proposed switch both the current 

definition of ‘‘startup’’ relied on and the 

proposed definition you plan to rely on; 

(B) Your request arrives to the 

Administrator at least 30 calendar days 

prior to the date that the switch is 

proposed to occur; 

(C) You revise and submit all other 

applicable plans, e.g., monitoring and 

emissions averaging, with your 

submission; 

(D) You maintain records of all 

information regarding your choice of the 

definition of ‘‘startup’’; and 

(E) You begin to use the revised 

definition of ‘‘startup’’ in the next 

reporting period after receipt of written 

acknowledgement from the 

Administrator of the switch. 

(f) You must submit the notifications 

in § 63.10000(h)(2) and (i)(2) that may 

apply to you by the dates specified. 

■ 18. Section 63.10031 is amended by 

revising paragraphs (c) introductory text 

and (c)(4) and (5) and adding paragraphs 

(c)(6), (7), (8), and (9) to read as follows: 

§ 63.10031 What reports must I submit and 

when? 

* * * * * 

(c) The compliance report must 

contain the information required in 

paragraphs (c)(1) through (9) of this 

section. 

* * * * * 

(4) Include the date of the most recent 

tune-up for each EGU. The date of the 

tune-up is the date the tune-up 

provisions specified in § 63.10021(e)(6) 

and (7) were completed. 

(5) Should you choose to rely on 

paragraph (2) of the definition of 

‘‘startup’’ in § 63.10042 for your EGU, 

for each instance of startup or shutdown 

you shall: 

(i) Include the maximum clean fuel 

storage capacity and the maximum 

hourly heat input that can be provided 

for each clean fuel determined 

according to the requirements of 

§ 63.10032(f). 

(ii) Include the information required 

to be monitored, collected, or recorded 

according to the requirements of 

§ 63.10020(e). 

(iii) If you choose to use CEMS to 

demonstrate compliance with numerical 

limits, include hourly average CEMS 

values and hourly average flow values 

during startup periods or shutdown 

periods. Use units of milligrams per 

cubic meter for PM CEMS values, 

micrograms per cubic meter for Hg 

CEMS values, and ppmv for HCl, HF, or 


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SO2 CEMS values. Use units of standard 

cubic meters per hour on a wet basis for 

flow values. 

(iv) If you choose to use a separate 

sorbent trap measurement system for 

startup or shutdown reporting periods, 

include hourly average mercury 

concentration values in terms of 

micrograms per cubic meter. 

(v) If you choose to use a PM CPMS, 

include hourly average operating 

parameter values in terms of the 

operating limit, as well as the operating 

parameter to PM correlation equation. 

(6) You must report emergency bypass 

information annually from EGUs with 

LEE status. 

(7) A summary of the results of the 

annual performance tests and 

documentation of any operating limits 

that were reestablished during the test, 

if applicable. If you are conducting stack 

tests once every 3 years to maintain LEE 

status, consistent with § 63.10006(b), the 

date of each stack test conducted during 

the previous 3 years, a comparison of 

emission level you achieved in each 

stack test conducted during the previous 

3 years to the 50 percent emission limit 

threshold required in 

§ 63.10005(h)(1)(i), and a statement as to 

whether there have been any 

operational changes since the last stack 

test that could increase emissions. 

(8) A certification. 

(9) If you have a deviation from any 

emission limit, work practice standard, 

or operating limit, you must also submit 

a brief description of the deviation, the 

duration of the deviation, emissions 

point identification, and the cause of the 

deviation. 

* * * * * 

■ 19. Section 63.10032 is amended by 

revising paragraph (f) to read as follows: 

§ 63.10032 What records must I keep? 

* * * * * 

(f) Regarding startup periods or 

shutdown periods: 

(1) Should you choose to rely on 

paragraph (1) of the definition of 

‘‘startup’’ in § 63.10042 for your EGU, 

you must keep records of the occurrence 

and duration of each startup or 

shutdown. 

(2) Should you choose to rely on 

paragraph (2) of the definition of 

‘‘startup’’ in § 63.10042 for your EGU, 

you must keep records of: 

(i) The determination of the maximum 

possible clean fuel capacity for each 

EGU; 

(ii) The determination of the 

maximum possible hourly clean fuel 

heat input and of the hourly clean fuel 

heat input for each EGU; and 

(iii) The information required in 

§ 63.10020(e). 

* * * * * 

■ 20. Section 63.10042 is amended by: 

■ a. Revising the definitions of ‘‘Coalfired electric utility steam generating 

unit,’’ ‘‘Coal refuse,’’ ‘‘Fossil fuel-fired,’’ 

‘‘Integrated gasification combined cycle 

electric utility steam generating unit or 

IGCC,’’ ‘‘Limited-use liquid oil-fired 

subcategory,’’ and ‘‘Natural gas-fired 

electric utility steam generating unit’’; 

■ b. Adding, in alphabetical order, 

definition of ‘‘Neural network or neural 

net’’; and 

■ c. Revising the definition of ‘‘Oil-fired 

electric utility steam generating unit.’’ 

The revisions and additions read as 

follows: 

§ 63.10042 What definitions apply to this 

subpart? 

* * * * * 

Coal-fired electric utility steam 

generating unit means an electric utility 

steam generating unit meeting the 

definition of ‘‘fossil fuel-fired’’ that 

burns coal for more than 10.0 percent of 

the average annual heat input during the 

3 previous calendar years after the 

compliance date for your facility in 

§ 63.9984 or for more than 15.0 percent 

of the annual heat input during any one 

of those calendar years. EGU owners 

and operators must estimate coal, oil, 

and natural gas usage for the first 3 

calendar years after the applicable 

compliance date and they are solely 

responsible for assuring compliance 

with this final rule or other applicable 

standard based on their fuel usage 

projections. After the first 3 years of 

compliance, EGUs are required to 

evaluate applicability based on coal or 

oil usage from the three previous 

calendars years on an annual rolling 

basis. 

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. 

* * * * * 

Fossil fuel-fired means an electric 

utility steam generating unit (EGU) that 

is capable of producing more than 25 

MW of electrical output from the 

combustion of fossil fuels. To be 

‘‘capable of combusting’’ fossil fuels, an 

EGU would need to have these fuels 

allowed in its operating permit and have 

the appropriate fuel handling facilities 

on-site or otherwise available (e.g., coal 

handling equipment, including coal 

storage area, belts and conveyers, 

pulverizers, etc.; oil storage facilities). In 

addition, fossil fuel-fired means any 

EGU that fired fossil fuels for more than 

10.0 percent of the average annual heat 

input during the 3 previous calendar 

years after the compliance date for your 

facility in § 63.9984 or for more than 

15.0 percent of the annual heat input 

during any one of those calendar years. 

EGU owners and operators must 

estimate coal, oil, and natural gas usage 

for the first 3 calendar years after the 

applicable compliance date and they are 

solely responsible for assuring 

compliance with this final rule or other 

applicable standard based on their fuel 

usage projections. After the first 3 years 

of compliance, EGUs are required to 

evaluate applicability based on coal or 

oil usage from the three previous 

calendars years on an annual rolling 

basis. 

* * * * * 

Integrated gasification combined 

cycle electric utility steam generating 

unit or IGCC means an electric utility 

steam generating unit meeting the 

definition of ‘‘fossil fuel-fired’’ that 

burns a synthetic gas derived from coal 

and/or solid oil-derived fuel for more 

than 10.0 percent of the average annual 

heat input during the 3 previous 

calendar years after the compliance date 

for your facility in § 63.9984 or for more 

than 15.0 percent of the annual heat 

input during any one of those calendar 

years in a combined-cycle gas turbine. 

EGU owners and operators must 

estimate coal, oil, and natural gas usage 

for the first 3 calendar years after the 

applicable compliance date and they are 

solely responsible for assuring 

compliance with this final rule or other 

applicable standard based on their fuel 

usage projections. No solid coal or solid 

oil-derived fuel is directly burned in the 

unit during operation. After the first 3 

years of compliance, EGUs are required 

to evaluate applicability based on coal 

or oil usage from the three previous 

calendars years on an annual rolling 

basis. 

* * * * * 

Limited-use liquid oil-fired 

subcategory means an oil-fired electric 

utility steam generating unit with an 

annual capacity factor when burning oil 

of less than 8 percent of its maximum 

or nameplate heat input, whichever is 

greater, averaged over a 24-month block 

contiguous period commencing on the 

first of the month following the 

compliance date specified in § 63.9984. 

* * * * * 

Natural gas-fired electric utility steam 

generating unit means an electric utility 

steam generating unit meeting the 

definition of ‘‘fossil fuel-fired’’ that is 

not a coal-fired, oil-fired, or IGCC 

electric utility steam generating unit and 


srobinson on DSK5SPTVN1PROD with RULES4
20190 Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 

that burns natural gas for more than 10.0 

percent of the average annual heat input 

during the 3 previous calendar years 

after the compliance date for your 

facility in § 63.9984 or for more than 

15.0 percent of the annual heat input 

during any one of those calendar years. 

EGU owners and operators must 

estimate coal, oil, and natural gas usage 

for the first 3 calendar years after the 

applicable compliance date and they are 

solely responsible for assuring 

compliance with this final rule or other 

applicable standard based on their fuel 

usage projections. 

* * * * * 

Neural network or neural net for 

purposes of this rule means an 

automated boiler optimization system. 

A neural network typically has the 

ability to process data from many inputs 

to develop, remember, update, and 

enable algorithms for efficient boiler 

operation. 

* * * * * 

Oil-fired electric utility steam 

generating unit means an electric utility 

steam generating unit meeting the 

definition of ‘‘fossil fuel-fired’’ that is 

not a coal-fired electric utility steam 

generating unit and that burns oil for 

more than 10.0 percent of the average 

annual heat input during the 3 previous 

calendar years after the compliance date 

for your facility in § 63.9984 or for more 

than 15.0 percent of the annual heat 

input during any one of those calendar 

years. EGU owners and operators must 

estimate coal, oil, and natural gas usage 

for the first 3 calendar years after the 

applicable compliance date and they are 

solely responsible for assuring 

compliance with this final rule or other 

applicable standard based on their fuel 

usage projections. After the first 3 years 

of compliance, EGUs are required to 

evaluate applicability based on coal or 

oil usage from the three previous 

calendars years on an annual rolling 

basis. 

* * * * * 

■ 21. Revise Table 1 to subpart UUUUU 

of part 63 to read as follows: 

TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS

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

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 to this Subpart . . . 

1. Coal-fired unit not low rank 

virgin coal.

a. Filterable particulate matter 

(PM).

9.0E-2 lb/MWh 1 ..................... Collect a minimum of 4 dscm per run. 

OR .......................................... OR 

Total non-Hg HAP metals ...... 6.0E-2 lb/GWh ........................ Collect a minimum of 4 dscm per run. 

OR .......................................... OR 

Individual HAP metals: ........... Collect a minimum of 3 dscm per run. 

Antimony (Sb) ......................... 8.0E-3 lb/GWh ........................

Arsenic (As) ............................ 3.0E-3 lb/GWh ........................

Beryllium (Be) ......................... 6.0E-4 lb/GWh ........................

Cadmium (Cd) ........................ 4.0E-4 lb/GWh ........................

Chromium (Cr) ........................ 7.0E-3 lb/GWh ........................

Cobalt (Co) ............................. 2.0E-3 lb/GWh ........................

Lead (Pb) ................................ 2.0E-2 lb/GWh ........................

Manganese (Mn) .................... 4.0E-3 lb/GWh ........................

Nickel (Ni) ............................... 4.0E-2 lb/GWh ........................

Selenium (Se) ......................... 5.0E-2 lb/GWh ........................

b. Hydrogen chloride (HCl) .... 1.0E-2 lb/MWh ........................ For Method 26A at appendix A–8 to part 60 

of this chapter, collect a minimum of 3 

dscm per run. For ASTM D6348–03 2 or 

Method 320 at appendix A to part 63 of 

this chapter, sample for a minimum of 1 

hour. 

OR 

Sulfur dioxide (SO2) 3 ............. 1.0 lb/MWh ............................. SO2 CEMS. 

c. Mercury (Hg) ...................... 3.0E-3 lb/GWh ........................ Hg CEMS or sorbent trap monitoring system 

only. 

2. Coal-fired units low rank virgin coal.a. Filterable particulate matter 

(PM).

9.0E-2 lb/MWh 1 ..................... Collect a minimum of 4 dscm per run. 

OR .......................................... OR 

Total non-Hg HAP metals ...... 6.0E-2 lb/GWh ........................ Collect a minimum of 4 dscm per run. 

OR .......................................... OR 

Individual HAP metals: ........... Collect a minimum of 3 dscm per run. 

Antimony (Sb) ......................... 8.0E-3 lb/GWh ........................

Arsenic (As) ............................ 3.0E-3 lb/GWh ........................

Beryllium (Be) ......................... 6.0E-4 lb/GWh ........................

Cadmium (Cd) ........................ 4.0E-4 lb/GWh ........................

Chromium (Cr) ........................ 7.0E-3 lb/GWh ........................

Cobalt (Co) ............................. 2.0E-3 lb/GWh ........................

Lead (Pb) ................................ 2.0E-2 lb/GWh ........................

Manganese (Mn) .................... 4.0E-3 lb/GWh ........................

Nickel (Ni) ............................... 4.0E-2 lb/GWh ........................

Selenium (Se) ......................... 5.0E-2 lb/GWh ........................

b. Hydrogen chloride (HCl) .... 1.0E-2 lb/MWh ........................ For Method 26A, collect a minimum of 3 

dscm per run For ASTM D6348–03 2 or 

Method 320, sample for a minimum of 1 

hour. 

OR 


srobinson on DSK5SPTVN1PROD with RULES4
Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 20191 

TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued 

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

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 to this Subpart . . . 

Sulfur dioxide (SO2) 3 ............. 1.0 lb/MWh ............................. SO2 CEMS. 

c. Mercury (Hg) ...................... 4.0E-2 lb/GWh ........................ Hg CEMS or sorbent trap monitoring system 

only. 

3. IGCC unit ............................. a. Filterable particulate matter 

(PM).

7.0E-2 lb/MWh 4 9.0E–2 lb/

MWh 5.

Collect a minimum of 1 dscm per run. 

OR .......................................... OR 

Total non-Hg HAP metals ...... 4.0E-1 lb/GWh ........................ Collect a minimum of 1 dscm per run. 

OR .......................................... OR 

Individual HAP metals: ........... Collect a minimum of 2 dscm per run. 

Antimony (Sb) ......................... 2.0E-2 lb/GWh ........................

Arsenic (As) ............................ 2.0E-2 lb/GWh ........................

Beryllium (Be) ......................... 1.0E-3 lb/GWh ........................

Cadmium (Cd) ........................ 2.0E-3 lb/GWh ........................

Chromium (Cr) ........................ 4.0E-2 lb/GWh ........................

Cobalt (Co) ............................. 4.0E-3 lb/GWh ........................

Lead (Pb) ................................ 9.0E-3 lb/GWh ........................

Manganese (Mn) .................... 2.0E-2 lb/GWh ........................

Nickel (Ni) ............................... 7.0E-2 lb/GWh ........................

Selenium (Se) ......................... 3.0E-1 lb/GWh ........................

b. Hydrogen chloride (HCl) .... 2.0E-3 lb/MWh ........................ For Method 26A, collect a minimum of 1 

dscm per run; for Method 26 at appendix 

A–8 to part 60 of this chapter, collect a 

minimum of 120 liters per run. For ASTM 

D6348–03 2 or Method 320, sample for a 

minimum of 1 hour. 

OR 

Sulfur dioxide (SO2) 3 ............. 4.0E-1 lb/MWh ........................ SO2 CEMS. 

c. Mercury (Hg) ...................... 3.0E-3 lb/GWh ........................ 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-1 lb/MWh 1 ..................... Collect a minimum of 1 dscm per run. 

OR .......................................... OR 

Total HAP metals ................... 2.0E-4 lb/MWh ........................ Collect a minimum of 2 dscm per run. 

OR .......................................... OR 

Individual HAP metals: ........... Collect a minimum of 2 dscm per run. 

Antimony (Sb) ......................... 1.0E-2 lb/GWh ........................

Arsenic (As) ............................ 3.0E-3 lb/GWh ........................

Beryllium (Be) ......................... 5.0E-4 lb/GWh ........................

Cadmium (Cd) ........................ 2.0E-4 lb/GWh ........................

Chromium (Cr) ........................ 2.0E-2 lb/GWh ........................

Cobalt (Co) ............................. 3.0E-2 lb/GWh ........................

Lead (Pb) ................................ 8.0E-3 lb/GWh ........................

Manganese (Mn) .................... 2.0E-2 lb/GWh ........................

Nickel (Ni) ............................... 9.0E-2 lb/GWh ........................

Selenium (Se) ......................... 2.0E-2 lb/GWh ........................

Mercury (Hg) .......................... 1.0E-4 lb/GWh ........................ For Method 30B at appendix A–8 to part 60 

of this chapter sample volume determination (Section 8.2.4), the estimated Hg concentration should nominally be < 1⁄2 the 

standard. 

b. Hydrogen chloride (HCl) .... 4.0E-4 lb/MWh ........................ For Method 26A, collect a minimum of 3 

dscm per run. For ASTM D6348–03 2 or 

Method 320, sample for a minimum of 1 

hour. 

c. Hydrogen fluoride (HF) ....... 4.0E-4 lb/MWh ........................ For Method 26A, collect a minimum of 3 

dscm per run. For ASTM D6348–03 2 or 

Method 320, sample for a minimum of 1 

hour. 

5. Liquid oil-fired unit—noncontinental (excluding limited-use liquid oil-fired subcategory units).a. Filterable particulate matter 

(PM).

2.0E–1 lb/MWh 1 ..................... Collect a minimum of 1 dscm per run. 

OR .......................................... OR 

Total HAP metals ................... 7.0E-3 lb/MWh ........................ Collect a minimum of 1 dscm per run. 

OR .......................................... OR 

Individual HAP metals: ........... Collect a minimum of 3 dscm per run. 


srobinson on DSK5SPTVN1PROD with RULES4
20192 Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 

TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued 

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

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 to this Subpart . . . 

Antimony (Sb) ......................... 8.0E-3 lb/GWh ........................

Arsenic (As) ............................ 6.0E-2 lb/GWh ........................

Beryllium (Be) ......................... 2.0E-3 lb/GWh ........................

Cadmium (Cd) ........................ 2.0E-3 lb/GWh ........................

Chromium (Cr) ........................ 2.0E-2 lb/GWh ........................

Cobalt (Co) ............................. 3.0E-1 lb/GWh ........................

Lead (Pb) ................................ 3.0E-2 lb/GWh ........................

Manganese (Mn) .................... 1.0E-1 lb/GWh ........................

Nickel (Ni) ............................... 4.1E0 lb/GWh .........................

Selenium (Se) ......................... 2.0E-2 lb/GWh ........................

Mercury (Hg) .......................... 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-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 2 or Method 320, sample for a 

minimum of 1 hour. 

c. Hydrogen fluoride (HF) ....... 5.0E-4 lb/MWh ........................ For Method 26A, collect a minimum of 3 

dscm per run.For ASTM D6348–03 2 or 

Method 320, sample for a minimum of 1 

hour. 

6. Solid oil-derived fuel-fired 

unit.

a. Filterable particulate matter 

(PM).

3.0E-2 lb/MWh 1 ..................... Collect a minimum of 1 dscm per run. 

OR .......................................... OR 

Total non-Hg HAP metals ...... 6.0E-1 lb/GWh ........................ Collect a minimum of 1 dscm per run. 

OR .......................................... OR 

Individual HAP metals: ........... Collect a minimum of 3 dscm per run. 

Antimony (Sb) ......................... 8.0E–3 lb/GWh .......................

Arsenic (As) ............................ 3.0E-3 lb/GWh ........................

Beryllium (Be) ......................... 6.0E-4 lb/GWh ........................

Cadmium (Cd) ........................ 7.0E-4 lb/GWh ........................

Chromium (Cr) ........................ 6.0E-3 lb/GWh ........................

Cobalt (Co) ............................. 2.0E-3 lb/GWh ........................

Lead (Pb) ................................ 2.0E-2 lb/GWh ........................

Manganese (Mn) .................... 7.0E-3 lb/GWh ........................

Nickel (Ni) ............................... 4.0E-2 lb/GWh ........................

Selenium (Se) ......................... 6.0E-3 lb/GWh ........................

b. Hydrogen chloride (HCl) .... 4.0E-4 lb/MWh ........................ For Method 26A, collect a minimum of 3 

dscm per run. For ASTM D6348–03 2 or 

Method 320, sample for a minimum of 1 

hour. 

OR 

Sulfur dioxide (SO2) 3 ............. 1.0 lb/MWh ............................. SO2 CEMS. 

c. Mercury (Hg) ...................... 2.0E-3 lb/GWh ........................ Hg CEMS or Sorbent trap monitoring system 

only. 

1 Gross output. 2 Incorporated by reference, see § 63.14. 3 You may not use the alternate SO2 limit if your EGU does not have some form of FGD system (or, in the case of IGCC EGUs, some other 

acid gas removal system either upstream or downstream of the combined cycle block) and SO2 CEMS installed. 4 Duct burners on syngas; gross output. 5 Duct burners on natural gas; gross output. 

■ 22. Revise Table 2 to subpart UUUUU 

of part 63 to read as follows: 


srobinson on DSK5SPTVN1PROD with RULES4
Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 20193 

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 to this Subpart . . . 

1. Coal-fired unit not low rank virgin coal.a. Filterable particulate matter 

(PM).

3.0E-2 lb/MMBtu or 3.0E-1 lb/

MWh 2.

Collect a minimum of 1 dscm per 

run. 

OR ................................................ OR 

Total non-Hg HAP metals ............ 5.0E-5 lb/MMBtu or 5.0E-1 lb/

GWh.

Collect a minimum of 1 dscm per 

run. 

OR ................................................ OR 

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 at appendix A–8 

to part 60 of this chapter, 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 at appendix A to part 63 

of this chapter, sample for a 

minimum of 1 hour. 

OR 

Sulfur dioxide (SO2) 4 ................... 2.0E-1 lb/MMBtu or 1.5E0 lb/MWh SO2 CEMS. 

c. Mercury (Hg) ............................. 1.2E0 lb/TBtu or 1.3E-2 lb/GWh .. LEE Testing for 30 days with a 

sampling period consistent with 

that given in section 5.2.1 of 

appendix A to this subpart per 

Method 30B at appendix A–8 to 

part 60 of this chapter run or 

Hg CEMS or sorbent trap monitoring system only. 

OR.

1.0E0 lb/TBtu or 1.1E-2 lb/GWh .. LEE Testing for 90 days with a 

sampling period consistent with 

that given in section 5.2.1 of 

appendix A to this subpart per 

Method 30B run or Hg CEMS 

or sorbent trap monitoring system only. 

2. Coal-fired unit low rank virgin 

coal.

a. Filterable particulate matter 

(PM).

3.0E-2 lb/MMBtu or 3.0E-1 lb/

MWh 2.

Collect a minimum of 1 dscm per 

run. 

OR ................................................ OR.

Total non-Hg HAP metals ............ 5.0E-5 lb/MMBtu or 5.0E-1 lb/

GWh.

Collect a minimum of 1 dscm per 

run. 

OR ................................................ OR.

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 ..


srobinson on DSK5SPTVN1PROD with RULES4
20194 Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 

TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued 

[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 to this Subpart . . . 

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 at appendix A–8 to 

part 60 of this chapter, 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) 4 ................... 2.0E-1 lb/MMBtu or 1.5E0 lb/MWh SO2 CEMS. 

c. Mercury (Hg) ............................. 4.0E0 lb/TBtu or 4.0E-2 lb/GWh .. LEE Testing for 30 days with a 

sampling period consistent with 

that given in section 5.2.1 of 

appendix A to this subpart per 

Method 30B run or Hg CEMS 

or sorbent trap monitoring system only. 

3. IGCC unit ................................... a. Filterable particulate matter 

(PM).

4.0E-2 lb/MMBtu or 4.0E-1 lb/

MWh 2.

Collect a minimum of 1 dscm per 

run. 

OR ................................................ OR 

Total non-Hg HAP metals ............ 6.0E-5 lb/MMBtu or 5.0E-1 lb/

GWh.

Collect a minimum of 1 dscm per 

run. 

OR ................................................ OR 

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/GWh .. LEE Testing for 30 days with a 

sampling period consistent with 

that given in section 5.2.1 of 

appendix A to this subpart per 

Method 30B run or Hg CEMS 

or sorbent trap monitoring system only. 

4. Liquid oil-fired unit—continental 

(excluding limited-use liquid oilfired subcategory units).

a. Filterable particulate matter 

(PM).

3.0E-2 lb/MMBtu or 3.0E-1 lb/

MWh 2.

Collect a minimum of 1 dscm per 

run. 

OR ................................................ OR 

Total HAP metals ......................... 8.0E-4 lb/MMBtu or 8.0E-3 lb/

MWh.

Collect a minimum of 1 dscm per 

run. 

OR ................................................ OR 

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 ..


srobinson on DSK5SPTVN1PROD with RULES4
Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 20195 

TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued 

[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 to this Subpart . . . 

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 2.

Collect a minimum of 1 dscm per 

run. 

OR ................................................ OR 

Total HAP metals ......................... 6.0E-4 lb/MMBtu or 7.0E-3 lb/

MWh.

Collect a minimum of 1 dscm per 

run. 

OR ................................................ OR 

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 unit ... a. Filterable particulate matter 

(PM).

8.0E-3 lb/MMBtu or 9.0E-2 lb/

MWh 2.

Collect a minimum of 1 dscm per 

run. 

OR ................................................ OR 

Total non-Hg HAP metals ............ 4.0E-5 lb/MMBtu or 6.0E-1 lb/

GWh.

Collect a minimum of 1 dscm per 

run. 

OR ................................................ OR 

Individual HAP metals: ................. Collect 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


srobinson on DSK5SPTVN1PROD with RULES4
20196 Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 

TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued 

[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 to this Subpart . . . 

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) 4 ................... 3.0E-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 a 

sampling period consistent with 

that given in section 5.2.1 of 

appendix A to this subpart per 

Method 30B run or Hg CEMS 

or sorbent trap monitoring system only. 

1For 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. 2Gross output. 

3 Incorporated by reference, see § 63.14. 

4You may not use the alternate SO2 limit if your EGU does not have some form of FGD system and SO2 CEMS installed. 

■ 23. Revise Table 3 to subpart UUUUU 

of part 63 to read as follows: 

TABLE 3 TO SUBPART UUUUU OF PART 63—WORK PRACTICE STANDARDS

[As stated in § 63.9991, you must comply with the following applicable work practice standards:] 

If your EGU is . . . You must meet the following . . . 

1. An existing EGU ...... Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar months, or each 48 calendar 

months if neural network combustion optimization software is employed, as specified in § 63.10021(e). 

2. A new or reconstructed EGU.Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar months, or each 48 calendar 

months if neural network combustion optimization software is employed, as specified in § 63.10021(e). 

3. A coal-fired, liquid 

oil-fired (excluding 

limited-use liquid oilfired subcategory 

units), or solid oil-derived fuel-fired EGU 

during startup.

a. You have the option of complying using either of the following work practice standards: 

(1) If you choose to comply using paragraph (1) of the definition of ‘‘startup’’ in § 63.10042, you must operate all 

CMS during startup. Startup means either the first-ever firing of fuel in a boiler for the purpose of producing 

electricity, or the firing of fuel in a boiler after a shutdown event for any purpose. Startup ends when any of the 

steam from the boiler is used to generate electricity for sale over the grid or for any other purpose (including on 

site use). For startup of a unit, you must use clean fuels as defined in § 63.10042 for ignition. Once you convert 

to firing coal, residual oil, or solid oil-derived fuel, you must engage all of the applicable control technologies except dry scrubber and SCR. You must start your dry scrubber and SCR systems, if present, appropriately to 

comply with relevant standards applicable during normal operation. You must comply with all applicable emissions limits at all times except for periods that meet the applicable definitions of startup and shutdown in this 

subpart. You must keep records during startup periods. You must provide reports concerning activities and 

startup periods, as specified in § 63.10011(g) and § 63.10021(h) and (i). 

(2) If you choose to comply using paragraph (2) of the definition of ‘‘startup’’ in § 63.10042, you must operate all 

CMS during startup. You must also collect appropriate data, and you must calculate the pollutant emission rate 

for each hour of startup. 

For startup of an EGU, you must use one or a combination of the clean fuels defined in § 63.10042 to the maximum extent possible, taking into account considerations such as boiler or control device integrity, throughout 

the startup period. You must have sufficient clean fuel capacity to engage and operate your PM control device 

within one hour of adding coal, residual oil, or solid oil-derived fuel to the unit. You must meet the startup period 

work practice requirements as identified in § 63.10020(e). 

Once you start firing coal, residual oil, or solid oil-derived fuel, you must vent emissions to the main stack(s). You 

must comply with the applicable emission limits beginning with the hour after startup ends. You must engage 

and operate your particulate matter control(s) within 1 hour of first firing of coal, residual oil, or solid oil-derived 

fuel. 


srobinson on DSK5SPTVN1PROD with RULES4
Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 20197 

TABLE 3 TO SUBPART UUUUU OF PART 63—WORK PRACTICE STANDARDS—Continued 

[As stated in § 63.9991, you must comply with the following applicable work practice standards:] 

If your EGU is . . . You must meet the following . . . 

You must start all other applicable control devices as expeditiously as possible, considering safety and manufacturer/supplier recommendations, but, in any case, when necessary to comply with other standards made applicable to the EGU by a permit limit or a rule other than this Subpart that require operation of the control devices. 

b. Relative to the syngas not fired in the combustion turbine of an IGCC EGU during startup, you must either: (1) 

Flare the syngas, or (2) route the syngas to duct burners, which may need to be installed, and route the flue 

gas from the duct burners to the heat recovery steam generator. 

c. If you choose to use just one set of sorbent traps to demonstrate compliance with the applicable Hg emission 

limit, you must comply with the limit at all times; otherwise, you must comply with the applicable emission limit 

at all times except for startup and shutdown periods. 

d. You must collect monitoring data during startup periods, as specified in § 63.10020(a) and (e). You must keep 

records during startup periods, as provided in §§ 63.10032 and 63.10021(h). You must provide reports concerning activities and startup periods, as specified in §§ 63.10011(g), 63.10021(i), and 63.10031. 

4. A coal-fired, liquid 

oil-fired (excluding 

limited-use liquid oilfired subcategory 

units), or solid oil-derived fuel-fired EGU 

during shutdown.

You must operate all CMS during shutdown. You must also collect appropriate data, and you must calculate the pollutant emission rate for each hour of shutdown for those pollutants for which a CMS is used. 

While firing coal, residual oil, or solid oil-derived fuel during shutdown, you must vent emissions to the main stack(s) 

and operate all applicable control devices and continue to operate those control devices after the cessation of coal, 

residual oil, or solid oil-derived fuel being fed into the EGU and for as long as possible thereafter considering operational and safety concerns. In any case, you must operate your controls when necessary to comply with other 

standards made applicable to the EGU by a permit limit or a rule other than this Subpart and that require operation 

of the control devices. 

If, in addition to the fuel used prior to initiation of shutdown, another fuel must be used to support the shutdown 

process, that additional fuel must be one or a combination of the clean fuels defined in § 63.10042 and must be 

used to the maximum extent possible, taking into account considerations such as not compromising boiler or 

control device integrity. 

Relative to the syngas not fired in the combustion turbine of an IGCC EGU during shutdown, you must either: (1) 

Flare the syngas, or (2) route the syngas to duct burners, which may need to be installed, and route the flue 

gas from the duct burners to the heat recovery steam generator. 

You must comply with all applicable emission limits at all times except during startup periods and shutdown periods at which time you must meet this work practice. You must collect monitoring data during shutdown periods, 

as specified in § 63.10020(a). You must keep records during shutdown periods, as provided in §§ 63.10032 and 

63.10021(h). Any fraction of an hour in which shutdown occurs constitutes a full hour of shutdown. You must 

provide reports concerning activities and shutdown periods, as specified in §§ 63.10011(g), 63.10021(i), and 

63.10031. 

■ 24. Revise Table 4 to subpart UUUUU 

of part 63 to read as follows: 

TABLE 4 TO SUBPART UUUUU OF PART 63 — OPERATING LIMITS FOR EGUS

[As stated in § 63.9991, you must comply with the applicable operating limits:] 

If you demonstrate 

compliance using . . . You must meet these operating limits . . . 

PM CPMS .................... Maintain the 30-boiler operating day rolling average PM CPMS output determined in accordance with the requirements 

of § 63.10023(b)(2) and obtained during the most recent performance test run demonstrating compliance with the filterable PM, total non-mercury HAP metals (total HAP metals, for liquid oil-fired units), or individual non-mercury 

HAP metals (individual HAP metals including Hg, for liquid oil-fired units) emissions limitation(s). 

■ 25. Revise Table 5 to subpart UUUUU 

of part 63 to read as follows: 

TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE TESTING REQUIREMENTS

[As stated in § 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected 

sources: 1] 

To conduct a performance test 

for the following pollutant . . . Using . . . 

You must perform the following activities, as applicable 

to your input- or output-based 

emission limit . . . 

Using . . .2

1. Filterable Particulate matter 

(PM).

Emissions Testing .................. a. Select sampling ports location and the number of traverse points.Method 1 at appendix A–1 to part 60 of this 

chapter. 

b. Determine velocity and volumetric flow-rate of the 

stack gas.

Method 2, 2A, 2C, 2F, 2G or 2H at appendix 

A–1 or A–2 to part 60 of this chapter. 


srobinson on DSK5SPTVN1PROD with RULES4
20198 Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 

TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE TESTING REQUIREMENTS—Continued 

[As stated in § 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected 

sources: 1] 

To conduct a performance test 

for the following pollutant . . . Using . . . 

You must perform the following activities, as applicable 

to your input- or output-based 

emission limit . . . 

Using . . .2

c. Determine oxygen and carbon dioxide concentrations 

of the stack gas.

Method 3A or 3B at appendix A–2 to part 60 

of this chapter, or ANSI/ASME PTC 19.10– 

1981.3

d. Measure the moisture content of the stack gas.Method 4 at appendix A–3 to part 60 of this 

chapter. 

e. Measure the filterable PM 

concentration.

Method 5 at appendix A–3 to part 60 of this 

chapter. 

For positive pressure fabric filters, Method 5D 

at appendix A–3 to part 60 of this chapter 

for filterable PM emissions. 

Note that the Method 5 front half temperature 

shall be 160° ± 14° C (320° ± 25° F). 

f. Convert emissions concentration to lb/MMBtu or 

lb/MWh emissions rates.

Method 19 F-factor methodology at appendix 

A–7 to part 60 of this chapter, or calculate 

using mass emissions rate and gross output data (see § 63.10007(e)). 

OR .......................................... OR.

PM CEMS ............................... a. Install, certify, operate, and 

maintain the PM CEMS.

Performance Specification 11 at appendix B 

to part 60 of this chapter and Procedure 2 

at appendix F to part 60 of this chapter. 

b. Install, certify, operate, and 

maintain the diluent gas, 

flow rate, and/or moisture 

monitoring systems.

Part 75 of this chapter and § 63.10010(a), 

(b), (c), and (d). 

c. Convert hourly emissions 

concentrations to 30 boiler 

operating day rolling average lb/MMBtu or lb/MWh 

emissions rates.

Method 19 F-factor methodology at appendix 

A–7 to part 60 of this chapter, or calculate 

using mass emissions rate and gross output data (see § 63.10007(e)). 

2. Total or individual non-Hg 

HAP metals.

Emissions Testing .................. a. Select sampling ports location and the number of traverse points..Method 1 at appendix A–1 to part 60 of this 

chapter. 

b. Determine velocity and volumetric flow-rate of the 

stack gas.

Method 2, 2A, 2C, 2F, 2G or 2H at appendix 

A–1 or A–2 to part 60 of this chapter. 

c. Determine oxygen and carbon dioxide concentrations 

of the stack gas.

Method 3A or 3B at appendix A–2 to part 60 

of this chapter, or ANSI/ASME PTC 19.10– 

1981.3

d. Measure the moisture content of the stack gas.Method 4 at appendix A–3 to part 60 of this 

chapter. 

e. Measure the HAP metals 

emissions concentrations 

and determine each individual HAP metals emissions concentration, as well 

as the total filterable HAP 

metals emissions concentration and total HAP 

metals emissions concentration.

Method 29 at appendix A–8 to part 60 of this 

chapter. For liquid oil-fired units, Hg is included in HAP metals and you may use 

Method 29, Method 30B at appendix A–8 

to part 60 of this chapter; for Method 29, 

you must report the front half and back half 

results separately. When using Method 29, 

report metals matrix spike and recovery 

levels. 

f. Convert emissions concentrations (individual HAP 

metals, total filterable HAP 

metals, and total HAP metals) to lb/MMBtu or lb/MWh 

emissions rates.

Method 19 F-factor methodology at appendix 

A–7 to part 60 of this chapter, or calculate 

using mass emissions rate and gross output data (see § 63.10007(e)). 

3. Hydrogen chloride (HCl) and 

hydrogen fluoride (HF).

Emissions Testing .................. a. Select sampling ports location and the number of traverse points..Method 1 at appendix A–1 to part 60 of this 

chapter. 

b. Determine velocity and volumetric flow-rate of the 

stack gas.

Method 2, 2A, 2C, 2F, 2G or 2H at appendix 

A–1 or A–2 to part 60 of this chapter. 

c. Determine oxygen and carbon dioxide concentrations 

of the stack gas.

Method 3A or 3B at appendix A–2 to part 60 

of this chapter, or ANSI/ASME PTC 19.10– 

1981.3

d. Measure the moisture content of the stack gas.Method 4 at appendix A–3 to part 60 of this 

chapter. 


srobinson on DSK5SPTVN1PROD with RULES4
Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 20199 

TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE TESTING REQUIREMENTS—Continued 

[As stated in § 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected 

sources: 1] 

To conduct a performance test 

for the following pollutant . . . Using . . . 

You must perform the following activities, as applicable 

to your input- or output-based 

emission limit . . . 

Using . . .2

e. Measure the HCl and HF 

emissions concentrations.

Method 26 or Method 26A at appendix A–8 

to part 60 of this chapter or Method 320 at 

appendix A to part 63 of this chapter or 

ASTM 6348–03 3 with 

(1) the following conditions when using 

ASTM D6348–03: 

(A) The test plan preparation and implementation in the Annexes to ASTM D6348–03, 

Sections A1 through A8 are mandatory; 

(B) For ASTM D6348–03 Annex A5 (Analyte 

Spiking Technique), the percent (%) R 

must be determined for each target analyte 

(see Equation A5.5); 

(C) For the ASTM D6348–03 test data to be 

acceptable for a target analyte, %R must 

be 70% ≥ R ≤ 130%; and 

3.e.1(D) The %R value for each 

compound must be reported in the test 

report and all field measurements 

corrected with the calculated %R value 

for that compound using the following 

equation: 

and 

To conduct a performance test 

for the following pollutant . . . 

(cont’d) 

Using . . . (cont’d) 

You must perform the following activities, as applicable 

to your input- or output-based 

emission limit . . . (cont’d) 

Using . . .2 (cont’d) 

................................................. ................................................. (2) spiking levels nominally no greater than 

two times the level corresponding to the 

applicable emission limit. 

Method 26A must be used if there are entrained water droplets in the exhaust 

stream. 

................................................. f. Convert emissions concentration to lb/MMBtu or lb/

MWh emissions rates.

Method 19 F-factor methodology at appendix 

A–7 to part 60 of this chapter, or calculate 

using mass emissions rate and gross output data (see § 63.10007(e)). 

OR .......................................... OR.

HCl and/or HF CEMS ............. a. Install, certify, operate, and 

maintain the HCl or HF 

CEMS.

Appendix B of this subpart. 

................................................. b. Install, certify, operate, and 

maintain the diluent gas, 

flow rate, and/or moisture 

monitoring systems.

Part 75 of this chapter and § 63.10010(a), (b), 

(c), and (d). 

................................................. c. Convert hourly emissions 

concentrations to 30 boiler 

operating day rolling average lb/MMBtu or lb/MWh 

emissions rates.

Method 19 F-factor methodology at appendix 

A–7 to part 60 of this chapter, or calculate 

using mass emissions rate and gross output data (see § 63.10007(e)). 

4. Mercury (Hg) ....................... Emissions Testing .................. a. Select sampling ports location and the number of traverse points.Method 1 at appendix A–1 to part 60 of this 

chapter or Method 30B at Appendix A–8 for 

Method 30B point selection. 

................................................. b. Determine velocity and volumetric flow-rate of the 

stack gas.

Method 2, 2A, 2C, 2F, 2G or 2H at appendix 

A–1 or A–2 to part 60 of this chapter. 

................................................. c. Determine oxygen and carbon dioxide concentrations 

of the stack gas.

Method 3A or 3B at appendix A–1 to part 60 

of this chapter, or ANSI/ASME PTC 19.10– 

1981.3


srobinson on DSK5SPTVN1PROD with RULES4ER06AP16.007</GPH>
20200 Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 

To conduct a performance test 

for the following pollutant . . . 

(cont’d) 

Using . . . (cont’d) 

You must perform the following activities, as applicable 

to your input- or output-based 

emission limit . . . (cont’d) 

Using . . .2 (cont’d) 

................................................. d. Measure the moisture content of the stack gas.Method 4 at appendix A–3 to part 60 of this 

chapter. 

................................................. e. Measure the Hg emission 

concentration.

Method 30B at appendix A–8 to part 60 of 

this chapter, ASTM D6784,3 or Method 29 

at appendix A–8 to part 60 of this chapter; 

for Method 29, you must report the front 

half and back half results separately. 

................................................. f. Convert emissions concentration to lb/TBtu or lb/

GWh emission rates.

Method 19 F-factor methodology at appendix 

A–7 to part 60 of this chapter, or calculate 

using mass emissions rate and gross output data (see § 63.10007(e)). 

OR .......................................... OR.

Hg CEMS ................................ a. Install, certify, operate, and 

maintain the CEMS.

Sections 3.2.1 and 5.1 of appendix A of this 

subpart. 

................................................. b. Install, certify, operate, and 

maintain the diluent gas, 

flow rate, and/or moisture 

monitoring systems.

Part 75 of this chapter and § 63.10010(a), (b), 

(c), and (d). 

................................................. c. Convert hourly emissions 

concentrations to 30 boiler 

operating day rolling average lb/TBtu or lb/GWh 

emissions rates.

Section 6 of appendix A to this subpart. 

OR .......................................... OR.

Sorbent trap monitoring system.a. Install, certify, operate, and 

maintain the sorbent trap 

monitoring system.

Sections 3.2.2 and 5.2 of appendix A to this 

subpart. 

................................................. b. Install, operate, and maintain the diluent gas, flow 

rate, and/or moisture monitoring systems.

Part 75 of this chapter and § 63.10010(a), (b), 

(c), and (d). 

................................................. c. Convert emissions concentrations to 30 boiler operating day rolling average 

lb/TBtu or lb/GWh emissions rates.

Section 6 of appendix A to this subpart. 

OR .......................................... OR.

LEE testing ............................. a. Select sampling ports location and the number of traverse points.Single point located at the 10% centroidal 

area of the duct at a port location per 

Method 1 at appendix A–1 to part 60 of this 

chapter or Method 30B at Appendix A–8 for 

Method 30B point selection. 

................................................. b. Determine velocity and volumetric flow-rate of the 

stack gas.

Method 2, 2A, 2C, 2F, 2G, or 2H at appendix 

A–1 or A–2 to part 60 of this chapter or 

flow monitoring system certified per appendix A of this subpart. 

................................................. c. Determine oxygen and carbon dioxide concentrations 

of the stack gas.

Method 3A or 3B at appendix A–1 to part 60 

of this chapter, or ANSI/ASME PTC 19.10– 

1981,3 or diluent gas monitoring systems 

certified according to part 75 of this chapter. 

................................................. d. Measure the moisture content of the stack gas.Method 4 at appendix A–3 to part 60 of this 

chapter, or moisture monitoring systems 

certified according to part 75 of this chapter. 

................................................. e. Measure the Hg emission 

concentration.

Method 30B at appendix A–8 to part 60 of 

this chapter; perform a 30 operating day 

test, with a maximum of 10 operating days 

per run (i.e., per pair of sorbent traps) or 

sorbent trap monitoring system or Hg 

CEMS certified per appendix A of this subpart. 

................................................. f. Convert emissions concentrations from the LEE 

test to lb/TBtu or lb/GWh 

emissions rates.

Method 19 F-factor methodology at appendix 

A–7 to part 60 of this chapter, or calculate 

using mass emissions rate and gross output data (see § 63.10007(e)). 

................................................. g. Convert average lb/TBtu or 

lb/GWh Hg emission rate to 

lb/year, if you are attempting to meet the 29.0 lb/year 

threshold.

Potential maximum annual heat input in TBtu 

or potential maximum electricity generated 

in GWh. 


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Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 20201 

To conduct a performance test 

for the following pollutant . . . 

(cont’d) 

Using . . . (cont’d) 

You must perform the following activities, as applicable 

to your input- or output-based 

emission limit . . . (cont’d) 

Using . . .2 (cont’d) 

5. Sulfur dioxide (SO2) ............ SO2 CEMS .............................. a. Install, certify, operate, and 

maintain the CEMS.

Part 75 of this chapter and § 63.10010(a) and 

(f). 

................................................. b. Install, operate, and maintain the diluent gas, flow 

rate, and/or moisture monitoring systems.

Part 75 of this chapter and § 63.10010(a), (b), 

(c), and (d). 

................................................. c. Convert hourly emissions 

concentrations to 30 boiler 

operating day rolling average lb/MMBtu or lb/MWh 

emissions rates.

Method 19 F-factor methodology at appendix 

A–7 to part 60 of this chapter, or calculate 

using mass emissions rate and gross output data (see § 63.10007(e)). 

1 Regarding emissions data collected during periods of startup or shutdown, see §§ 63.10020(b) and (c) and 63.10021(h). 

2See Tables 1 and 2 to this subpart for required sample volumes and/or sampling run times. 

3 Incorporated by reference, see § 63.14. 

■ 26. Revise Table 6 to subpart UUUUU 

of part 63 to read as follows: 

TABLE 6 TO SUBPART UUUUU OF PART 63—ESTABLISHING PM CPMS OPERATING LIMITS

[As stated in § 63.10007, you must comply with the following requirements for establishing operating limits:] 

If you have an applicable emission limit 

for . . . 

And you choose to establish PM 

CPMS operating limits, you must 

. . . 

And . . . Using . . . According to the following procedures . . . 

Filterable Particulate 

matter (PM), total 

non-mercury HAP 

metals, individual 

non-mercury HAP 

metals, total HAP 

metals, or individual 

HAP metals for an 

EGU.

Install, certify, maintain, and operate a PM CPMS for monitoring 

emissions discharged to the atmosphere according to 

§ 63.10010(h)(1).

Establish a site-specific operating limit 

in units of PM 

CPMS output signal 

(e.g., milliamps, mg/

acm, or other raw 

signal).

Data from the PM 

CPMS and the PM 

or HAP metals performance tests.

1. Collect PM CPMS output data 

during the entire period of the 

performance tests. 

2. Record the average hourly PM 

CPMS output for each test run 

in the performance test. 

3. Determine the PM CPMS operating limit in accordance with 

the requirements of 

§ 63.10023(b)(2) from data obtained during the performance 

test demonstrating compliance 

with the filterable PM or HAP 

metals emissions limitations. 

■ 27. Revise Table 8 to subpart UUUUU 

of part 63 to read as follows: 

TABLE 8 TO SUBPART UUUUU OF PART 63—REPORTING REQUIREMENTS

[As stated in § 63.10031, you must comply with the following requirements:] 

You must submit 

a The report must contain . . . You must submit the report . . . 

1. Compliance 

report.

a. Information required in § 63.10031(c)(1) through (9); and .................................... Semiannually according to the requirements in § 63.10031(b). 

b. If there are no deviations from any emission limitation (emission limit and operating limit) that applies to you and there are no deviations from the requirements for work practice standards in Table 3 to this subpart that apply to you, a 

statement that there were no deviations from the emission limitations and work 

practice standards during the reporting period. If there were no periods during 

which the CMSs, including continuous emissions monitoring system, and operating parameter monitoring systems, were out-of-control as specified in 

§ 63.8(c)(7), a statement that there were no periods during which the CMSs 

were out-of-control during the reporting period; and.

c. If you have a deviation from any emission limitation (emission limit and operating limit) or work practice standard during the reporting period, the report 

must contain the information in § 63.10031(d). If there were periods during 

which the CMSs, including continuous emissions monitoring systems and continuous parameter monitoring systems, were out-of-control, as specified in 

§ 63.8(c)(7), the report must contain the information in § 63.10031(e)..


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20202 Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 

■ 28. Revise Table 9 to subpart UUUUU 

of part 63 to read as follows: 

TABLE 9 TO SUBPART UUUUU OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART UUUUU 

[As stated in § 63.10040, you must comply with the applicable General Provisions according to the following:] 

Citation Subject Applies to subpart UUUUU 

§ 63.1 .................................................................. Applicability ...................................................... Yes. 

§ 63.2 .................................................................. Definitions ........................................................ Yes. Additional terms defined in § 63.10042. 

§ 63.3 .................................................................. Units and Abbreviations ................................... Yes. 

§ 63.4 .................................................................. Prohibited Activities and Circumvention .......... Yes. 

§ 63.5 .................................................................. Preconstruction Review and Notification Requirements.Yes. 

§ 63.6(a), (b)(1) through (5), (b)(7), (c), (f)(2) 

and (3), (h)(2) through (9), (i), (j).

Compliance with Standards and Maintenance 

Requirements.

Yes. 

§ 63.6(e)(1)(i) ...................................................... General Duty to minimize emissions ............... No. See § 63.10000(b) for general duty requirement. 

§ 63.6(e)(1)(ii) ..................................................... Requirement to correct malfunctions ASAP .... No. 

§ 63.6(e)(3) ......................................................... SSM Plan requirements ................................... No.

§ 63.6(f)(1) .......................................................... SSM exemption ................................................ No. 

§ 63.6(h)(1) ......................................................... SSM exemption ................................................ No. 

§ 63.6(g) .............................................................. Compliance with Standards and Maintenance 

Requirements, Use of an alternative nonopacity emission standard.

Yes. See §§ 63.10011(g)(4) and 

63.10021(h)(4) for additional requirements. 

§ 63.7(e)(1) ......................................................... Performance testing ......................................... No. See § 63.10007. 

§ 63.8 .................................................................. Monitoring Requirements ................................. Yes. 

§ 63.8(c)(1)(i) ...................................................... General duty to minimize emissions and CMS 

operation.

No. See § 63.10000(b) for general duty requirement. 

§ 63.8(c)(1)(iii) ..................................................... Requirement to develop SSM Plan for CMS ... No. 

§ 63.8(d)(3) ......................................................... Written procedures for CMS ............................ Yes, except for last sentence, which refers to 

an SSM plan. SSM plans are not required. 

§ 63.9 .................................................................. Notification Requirements ................................ Yes, except (1) for the 60-day notification 

prior to conducting a performance test in 

§ 63.9(e); instead use a 30-day notification 

period per § 63.10030(d), (2) the notification 

of the CMS performance evaluation in 

§ 63.9(g)(1) is limited to RATAs, and (3) the 

information required per § 63.9(h)(2)(i); instead provide the information required per 

§ 63.10030(e)(1) through (e)(6) and (e)(8). 

§ 63.10(a), (b)(1), (c), (d)(1) and (2), (e), and (f) Recordkeeping and Reporting Requirements Yes, except for the requirements to submit 

written reports under § 63.10(e)(3)(v). 

§ 63.10(b)(2)(i) .................................................... Recordkeeping of occurrence and duration of 

startups and shutdowns.

No. 

§ 63.10(b)(2)(ii) ................................................... Recordkeeping of malfunctions ....................... No. See § 63.10001 for recordkeeping of (1) 

occurrence and duration and (2) actions 

taken during malfunction. 

§ 63.10(b)(2)(iii) .................................................. Maintenance records ....................................... Yes. 

§ 63.10(b)(2)(iv) .................................................. Actions taken to minimize emissions during 

SSM.

No. 

§ 63.10(b)(2)(v) ................................................... Actions taken to minimize emissions during 

SSM.

No. 

§ 63.10(b)(2)(vi) .................................................. Recordkeeping for CMS malfunctions ............. Yes. 

§ 63.10(b)(2)(vii) through (ix) .............................. Other CMS requirements ................................. Yes. 

§ 63.10(b)(3) and (d)(3) through (5) ................... .......................................................................... No. 

§ 63.10(c)(7) ....................................................... Additional recordkeeping requirements for 

CMS—identifying exceedances and excess 

emissions.

Yes. 

§ 63.10(c)(8) ....................................................... Additional recordkeeping requirements for 

CMS—identifying exceedances and excess 

emissions.

Yes. 

§ 63.10(c)(10) ..................................................... Recording nature and cause of malfunctions .. No. See § 63.10032(g) and (h) for malfunctions recordkeeping requirements. 

§ 63.10(c)(11) ..................................................... Recording corrective actions ........................... No. See § 63.10032(g) and (h) for malfunctions recordkeeping requirements. 

§ 63.10(c)(15) ..................................................... Use of SSM Plan ............................................. No. 

§ 63.10(d)(5) ....................................................... SSM reports ..................................................... No. See § 63.10021(h) and (i) for malfunction 

reporting requirements. 

§ 63.11 ................................................................ Control Device Requirements .......................... No. 

§ 63.12 ................................................................ State Authority and Delegation ........................ Yes. 

§§ 63.13 through 63.16 ...................................... Addresses, Incorporation by Reference, Availability of Information, Performance Track 

Provisions.

Yes. 


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Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 20203 

TABLE 9 TO SUBPART UUUUU OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART UUUUU—Continued 

[As stated in § 63.10040, you must comply with the applicable General Provisions according to the following:] 

Citation Subject Applies to subpart UUUUU 

§§ 63.1(a)(5),(a)(7) through (9), (b)(2), (c)(3) 

and (4), (d), 63.6(b)(6), (c)(3) and (4), (d), 

(e)(2), (e)(3)(ii), (h)(3), (h)(5)(iv), 63.8(a)(3), 

63.9(b)(3), (h)(4), 63.10(c)(2) through (4), 

(c)(9)..

Reserved .......................................................... No. 

■ 29. Appendix A to subpart UUUUU of 

part 63 is amended by revising 

paragraphs 3.2.1.2.1, 4.1.1.1, and 

4.1.1.3, table A–1, paragraphs 4.1.1.5, 

4.1.1.5.2, 5.1.2.1, and 5.1.2.3, table A–2, 

and paragraphs 5.2.1, 6.2.2.3, and 

7.1.8.5 and adding paragraph 7.1.2.6 to 

read as follows: 

Appendix A to Subpart UUUUU of Part 

63—Hg Monitoring Provisions 

* * * * * 

3. Mercury Emissions Measurement 

Methods 

* * * * * 

3.2.1.2.1 NIST Traceability. Only 

NIST-certified or NIST-traceable 

calibration gas standards and reagents 

(as defined in paragraphs 3.1.4 and 3.1.5 

of this appendix), and including, but not 

limited to, Hg gas generators and Hg gas 

cylinders, shall be used for the tests and 

procedures required under this subpart. 

Calibration gases with known 

concentrations of Hg0 and HgCl2 are 

required. Special reagents and 

equipment may be needed to prepare 

the Hg0 and HgCl2 gas standards (e.g., 

NIST-traceable solutions of HgCl2 and 

gas generators equipped with mass flow 

controllers). 

* * * * * 

4. Certification and Recertification 

Requirements 

* * * * * 

4.1.1.1 7-Day Calibration Error Test. 

Perform the 7-day calibration error test 

on 7 consecutive source operating days, 

using a zero-level gas and either a highlevel or a mid-level calibration gas 

standard (as defined in paragraphs 3.1.8, 

3.1.10, and 3.1.11 of this appendix). Use 

a NIST-traceable elemental Hg gas 

standard (as defined in paragraphs 3.1.4 

of this appendix) for the test. If your Hg 

CEMS lacks an integrated elemental Hg 

gas generator, you may continue to use 

NIST-traceable oxidized Hg gases for the 

7-day calibration error test (or the daily 

calibration error check) until such time 

as NIST-traceable compressed elemental 

Hg gas standards, at appropriate 

concentration levels, are available from 

gas vendors. If moisture is added to the 

calibration gas, the dilution effect of the 

moisture and/or chlorine addition on 

the calibration gas concentration must 

be accounted for in an appropriate 

manner. Operate the Hg CEMS in its 

normal sampling mode during the test. 

The calibrations should be 

approximately 24 hours apart, unless 

the 7-day test is performed over nonconsecutive calendar days. On each day 

of the test, inject the zero-level and 

upscale gases in sequence and record 

the analyzer responses. Pass the 

calibration gas through all filters, 

scrubbers, conditioners, and other 

monitor components used during 

normal sampling, and through as much 

of the sampling probe as is practical. Do 

not make any manual adjustments to the 

monitor (i.e., resetting the calibration) 

until after taking measurements at both 

the zero and upscale concentration 

levels. If automatic adjustments are 

made following both injections, conduct 

the calibration error test such that the 

magnitude of the adjustments can be 

determined, and use only the 

unadjusted analyzer responses in the 

calculations. Calculate the calibration 

error (CE) on each day of the test, as 

described in Table A–1 of this 

appendix. The CE on each day of the 

test must either meet the main 

performance specification or the 

alternative specification in Table A–1 of 

this appendix. 

* * * * * 

4.1.1.3 Three-Level System Integrity 

Check. Perform the 3-level system 

integrity check using low, mid, and 

high-level calibration gas concentrations 

generated by a NIST-traceable source of 

oxidized Hg. If your Hg CEMS lacks an 

integrated elemental Hg gas generator, 

you may continue to use NIST-traceable 

oxidized Hg gases for the 7-day 

calibration error test (or the daily 

calibration error check) until such time 

as NIST-traceable compressed elemental 

Hg gas standards, at appropriate 

concentration levels, are available from 

gas vendors. Follow the same basic 

procedure as for the linearity check. If 

moisture and/or chlorine is added to the 

calibration gas, the dilution effect of the 

moisture and/or chlorine addition on 

the calibration gas concentration must 

be accounted for in an appropriate 

manner. Calculate the system integrity 

error (SIE), as described in Table A–1 of 

this appendix. The SIE must either meet 

the main performance specification or 

the alternative specification in Table A– 

1 of this appendix. 

TABLE A–1—REQUIRED CERTIFICATION TESTS AND PERFORMANCE SPECIFICATIONS FOR Hg CEMS 

For this required certification 

test . . . 

The main performance specification 1 is . . . The alternate performance 

specification 1 is . . . 

And the conditions of the alternate specification are . . . 

7-day calibration error test 2 6 ... |R ¥ A| ≤ 5.0% of span value, 

for both the zero and 

upscale gases, on each of 

the 7 days..

|R ¥ A| ≤ 1.0 μg/scm ............. The alternate specification may be used on 

any day of the test. 

Linearity check 3 6 ..................... |R ¥ Aavg | ≤ 10.0% of the reference gas concentration at 

each calibration gas level 

(low, mid, or high)..

|R ¥ Aavg | ≤ 0.8 μg/scm ........ The alternate specification may be used at 

any gas level. 

3-level system integrity check 4 |R ¥ Aavg | ≤ 10.0% of the reference gas concentration at 

each calibration gas level..

|R ¥ Aavg | ≤ 0.8 μg/scm ........ The alternate specification may be used at 

any gas level. 


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20204 Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 

TABLE A–1—REQUIRED CERTIFICATION TESTS AND PERFORMANCE SPECIFICATIONS FOR Hg CEMS—Continued 

For this required certification 

test . . . 

The main performance specification 1 is . . . The alternate performance 

specification 1 is . . . 

And the conditions of the alternate specification are . . . 

RATA ........................................ 20.0% RA ............................... |RMavg ¥ Cavg| + |CC| ≤ 0.5 

μg/scm 7.

RMavg < 2.5μg/scm 

Cycle time test 5 ....................... 15 minutes where the stability 

criteria are readings change 

by < 2.0% of span or by ≤ 

0.5 μg/scm, for 2 minutes..

1 Note that |R ¥ A| is the absolute value of the difference between the reference gas value and the analyzer reading. |R ¥ Aavg| is the absolute value of the difference between the reference gas concentration and the average of the analyzer responses, at a particular gas level. 2 Use elemental Hg standards; a mid-level or high-level upscale gas may be used. 

3 Use elemental Hg standards. 

4 Use oxidized Hg standards. 

5 Use elemental Hg standards; a high-level upscale gas must be used. The cycle time test is not required for Hg CEMS that use integrated 

batch sampling; however, those monitoring systems must be capable of recording at least one Hg concentration reading every 15 minutes. 6 If your Hg CEMS lacks an integrated elemental Hg gas generator, you may continue to use NIST-traceable oxidized Hg gases until such time 

as NIST-traceable compressed elemental Hg gas standards, at appropriate concentration levels, are available from gas vendors. 7 Note that |RMavg ¥ Cavg| is the absolute difference between the mean reference method value and the mean CEMS value from the RATA; 

CC is the confidence coefficient from Equation 2–5 of Performance Specification 2 in appendix B to part 60 of this chapter. 

* * * * * 

4.1.1.5 Relative Accuracy Test Audit 

(RATA). Perform the RATA of the Hg 

CEMS at normal load. Acceptable Hg 

reference methods for the RATA include 

ASTM D6784–02 (Reapproved 2008), 

‘‘Standard Test Method for Elemental, 

Oxidized, Particle-Bound and Total 

Mercury in Flue Gas Generated from 

Coal-Fired Stationary Sources (Ontario 

Hydro Method)’’ (incorporated by 

reference, see § 63.14) and Methods 29, 

30A, and 30B in appendix A–8 to part 

60 of this chapter. When Method 29 or 

ASTM D6784–02 is used, paired 

sampling trains are required and the 

filterable portion of the sample need not 

be included when making comparisons 

to the Hg CEMS results for purposes of 

a RATA. To validate a Method 29 or 

ASTM D6784–02 test run, calculate the 

relative deviation (RD) using Equation 

A–1 of this section, and assess the 

results as follows to validate the run. 

The RD must not exceed 10 percent, 

when the average Hg concentration is 

greater than 1.0 mg/dscm. If the RD 

specification is met, the results of the 

two samples shall be averaged 

arithmetically. 

Where: 

RD = Relative Deviation between the Hg 

concentrations of samples ‘‘a’’ and ‘‘b’’ 

(percent), 

Ca = Hg concentration of Hg sample ‘‘a’’ (m g/ 

dscm), and 

Cb = Hg concentration of Hg sample ‘‘b’’ (m g/ 

dscm). 

* * * * * 

4.1.1.5.2 Calculation of RATA 

Results. Calculate the relative accuracy 

(RA) of the monitoring system, on a 

m g/scm basis, as described in section 12 

of Performance Specification (PS) 2 in 

appendix B to part 60 of this chapter 

(see Equations 2–3 through 2–6 of PS2) 

including the option to substitute the 

emission limit value (in this case the 

equivalent concentration) in the 

denominator of Equation 2–6 in place of 

the average RM value when the average 

emissions for the test are less than 50 

percent of the applicable emissions 

limit. For purposes of calculating the 

relative accuracy, ensure that the 

reference method and monitoring 

system data are on a consistent basis, 

either wet or dry. The CEMS must either 

meet the main performance 

specification or the alternative 

specification in Table A–1 of this 

appendix. 

* * * * * 

5. Ongoing Quality Assurance (QA) and 

Data Validation 

* * * * * 

5.1.2.1 Calibration error tests of the 

Hg CEMS are required daily, except 

during unit outages. Use a NISTtraceable elemental Hg gas standard for 

these calibrations. If your Hg CEMS 

lacks an integrated elemental Hg gas 

generator, you may continue to use 

NIST-traceable oxidized Hg gases for the 

7-day calibration error test (or the daily 

calibration error check) until such time 

as NIST-traceable compressed elemental 

Hg gas standards, at appropriate 

concentration levels, are available from 

gas vendors. Both a zero-level gas and 

either a mid-level or high-level gas are 

required for these calibrations. 

* * * * * 

5.1.2.3 Perform a single-level system 

integrity check weekly, i.e., once every 

7 operating days (see the third column 

in Table A–2 of this appendix). 

* * * * * 


srobinson on DSK5SPTVN1PROD with RULES4ER06AP16.008</GPH>
Federal Register / Vol. 81, No. 66 / Wednesday, April 6, 2016 / Rules and Regulations 20205 

TABLE A–2—ON-GOING QA TEST REQUIREMENTS FOR Hg CEMS 

Perform this type of QA test 

. . . At this frequency . . . With these qualifications and exceptions . . . Acceptance criteria . . . 

Calibration error test 5 .............. Daily ........................................ • Use either a mid- or highlevel gas.

• Use elemental Hg ...............

• Calibrations are not required when the unit is not 

in operation..

|R ¥ A| ≤ 5.0% of span value 

or 

|R ¥ A| ≤ 1.0 μg/scm. 

Single-level system integrity 

check.

Weekly 1 .................................. • Use oxidized Hg—either 

mid- or high-level.

|R ¥ Aavg| ≤ 10.0% of the reference gas 

value 

or 

|R ¥ Aavg| ≤ 0.8 μg/scm. 

Linearity check or 3-level system integrity check.Quarterly 3 ............................... • Required in each ‘‘QA operating quarter’’ 2 and no less 

than once every 4 calendar 

quarters.

• 168 operating hour grace 

period available.

• Use elemental Hg for linearity check.

• Use oxidized Hg for system 

integrity check.

|R ¥ Aavg | ≤ 10.0% of the reference gas 

value, at each calibration gas level 

or 

|R ¥ Aavg| ≤ 0.8 μg/scm. 

RATA ........................................ Annual 4 .................................. • Test deadline may be extended for ‘‘non-QA operating quarters,’’ up to a 

maximum of 8 quarters 

from the quarter of the previous test..

• 720 operating hour grace 

period available.

≤20.0% RA when Cavg ≥ 2.5 μg/scm 

or 

|RMavg ¥ Cavg| + |CC| ≤ 0.5 μgμ/scm, if 

RMavg < 2.5 μg/scm. 

1 ‘‘Weekly’’ means once every 7 operating days. 

2A ‘‘QA operating quarter’’ is a calendar quarter with at least 168 unit or stack operating hours. 

3 ‘‘Quarterly’’ means once every QA operating quarter. 

4 ‘‘Annual’’ means once every four QA operating quarters. 

5 If your Hg CEMS lacks an integrated elemental Hg gas generator, you may continue to use NIST-traceable oxidized Hg gases until such time 

as NIST-traceable compressed elemental Hg gas standards, at appropriate concentration levels, are available from gas vendors. 

* * * * * 

5.2.1 Each sorbent trap monitoring 

system shall be continuously operated 

and maintained in accordance with 

Performance Specification (PS) 12B in 

appendix B to part 60 of this chapter. 

The QA/QC criteria for routine 

operation of the system are summarized 

in Table 12B–1 of PS 12B. Each pair of 

sorbent traps may be used to sample the 

stack gas for up to 15 operating days. 

* * * * * 

6. Data Reductions and Calculations 

* * * * * 

6.2.2.3 The applicable gross outputbased Hg emission rate limit in Table 1 

or 2 to this subpart must be met on a 

30- (or 90-) boiler operating day rolling 

average basis, except as otherwise 

provided in § 63.10009(a)(2). Use 

Equation A–5 of this appendix to 

calculate the Hg emission rate for each 

averaging period. 

Where: 

Eo = Hg emission rate for the averaging 

period (lb/GWh), 

Eho = Gross output-based hourly Hg emission 

rate for unit or stack sampling hour ‘‘h’’ 

in the averaging period, from Equation 

A–4 of this appendix (lb/GWh), and 

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. Recordkeeping and Reporting 

* * * * * 

7.1.2.6 The EGUs that constitute an 

emissions averaging group. 

* * * * * 

7.1.8.5 If applicable, a code to 

indicate that the default gross output (as 

defined in § 63.10042) was used to 

calculate the Hg emission rate. 

* * * * * 

■ 30. Appendix B to subpart UUUUU of 

part 63 is amended by: 

■ a. Revising paragraphs 2.1 and 2.3; 

■ b. Adding paragraphs 2.3.1 and 2.3.2; 

■ c. Revising paragraphs 3.1 and 3.2 and 

adding paragraph 3.3; 

■ d. Adding introductory text to section 

5; 

■ e. Revising paragraphs 5.1, 5.1.2, 5.2, 

and 5.3; 

■ f. Adding paragraphs 5.4, 5.4.1, 5.4.2, 

5.4.2.1, 5.4.2.2, 5.4.2.2.1, 5.4.2.2.2, 

5.4.2.3, 5.4.2.3.1, 5.4.2.3.2, 5.4.2.3.3, and 

5.4.3; and 

■ g. Revising section 8 introductory text 

and paragraph 9.3.2. 

The revisions and additions read as 

follows: 

Appendix B to Subpart UUUUU of Part 

63—HCl and HF Monitoring Provisions 

* * * * * 

2. Monitoring of HCl and/or HF 

Emissions 

2.1 Monitoring System Installation 

Requirements. Install HCl and/or HF 

CEMS and any additional monitoring 

systems needed to convert pollutant 

concentrations to units of the applicable 

emissions limit in accordance with 

§ 63.10010(a) and either Performance 

Specification 15 (PS 15) of appendix B 

to part 60 of this chapter for extractive 

Fourier Transform Infrared 

Spectroscopy (FTIR) continuous 

emissions monitoring systems or 

Performance Specification 18 (PS 18) of 

appendix B to part 60 of this chapter for 

HCl CEMS. 

* * * * * 


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2.3 FTIR Monitoring System 

Equipment, Supplies, Definitions, and 

General Operation. The following 

provisions apply: 

2.3.1 PS 15, Sections 2.0, 3.0, 4.0, 

5.0, 6.0, and 10.0 of appendix B to part 

60 of this chapter; or 

2.3.2 PS 18, Sections 3.0, 6.0, and 

11.0 of appendix B to part 60 of this 

chapter. 

3. Initial Certification Procedures 

* * * * * 

3.1 If you choose to follow PS 15 of 

appendix B to part 60 of this chapter, 

then your HCl and/or HF CEMS must be 

certified according to PS 15 using the 

procedures for gas auditing and 

comparison to a reference method (RM) 

as specified in sections 3.1.1 and 3.1.2 

below. 

* * * * * 

3.2 If you choose to follow PS 18 of 

appendix B to part 60 of this chapter, 

then your HCl CEMS must be certified 

according to PS 18, sections 7.0, 8.0, 

11.0, 12.0, and 13.0. 

3.3 Any additional stack gas flow 

rate, diluent gas, and moisture 

monitoring system(s) needed to express 

pollutant concentrations in units of the 

applicable emissions limit must be 

certified according to part 75 of this 

chapter. 

* * * * * 

5. On-Going Quality Assurance 

Requirements 

On-going QA test requirements for 

HCl and HF CEMS must be 

implemented as follows: 

5.1 If you choose to follow 

Performance Specification 15 (PS 15) of 

appendix B to part 60 of this chapter, 

then the quality assurance/quality 

control procedures of PS 15 shall apply 

as set forth in sections 5.1.1 through 

5.1.3 and 5.4.2 of this appendix. 

* * * * * 

5.1.2 On a quarterly basis, you must 

conduct a gas audit of the HCl and/or 

HF CEMS as described in section 3.1.1 

of this appendix. For the purposes of 

this appendix, ‘‘quarterly’’ means once 

every ‘‘QA operating quarter’’ (as 

defined in section 3.1.20 of appendix A 

to this subpart). You have the option to 

use HCl gas in lieu of HF gas for 

conducting this audit on an HF CEMS. 

To the extent practicable, perform 

consecutive quarterly gas audits at least 

30 days apart. The initial quarterly audit 

is due in the first QA operating quarter 

following the calendar quarter in which 

certification testing of the CEMS is 

successfully completed. Up to three 

consecutive exemptions from the 

quarterly audit requirement are allowed 

for ‘‘non-QA operating quarters’’ (i.e., 

calendar quarters in which there are less 

than 168 unit or stack operating hours). 

However, no more than four consecutive 

calendar quarters may elapse without 

performing a gas audit, except as 

otherwise provided in section 5.4.2.2.1 

of this appendix. 

* * * * * 

5.2 If you choose to follow 

Performance Specification PS 18 of 

appendix B to part 60 of this chapter, 

then the quality assurance/quality 

control procedures in Procedure 6 of 

appendix F to part 60 of this chapter 

shall apply. The quarterly and annual 

QA tests required under Procedure 6 

shall be performed, respectively, at the 

frequencies specified in sections 5.1.2 

and 5.1.3 of this appendix. 

5.3 Stack gas flow rate, diluent gas, 

and moisture monitoring systems must 

meet the applicable on-going QA test 

requirements of part 75 of this chapter. 

* * * * * 

5.4 Data Validation. 

5.4.1 Out-of-Control Periods. An HCl 

or HF CEMS that is used to provide data 

under this appendix is considered to be 

out-of-control, and data from the CEMS 

may not be reported as quality-assured, 

when any acceptance criteria for a 

required QA test is not met. The HCl or 

HF CEMS is also considered to be outof-control when a required QA test is 

not performed on schedule or within an 

allotted grace period. To end an out-ofcontrol period, the QA test that was 

either failed or not done on time must 

be performed and passed. Out-of-control 

periods are counted as hours of 

monitoring system downtime. 

5.4.2 Grace Periods. For the 

purposes of this appendix, a ‘‘grace 

period’’ is defined as a specified number 

of unit or stack operating hours after the 

deadline for a required qualityassurance test of a continuous monitor 

has passed, in which the test may be 

performed and passed without loss of 

data. 

5.4.2.1 For the monitoring systems 

described in section 5.3 of this 

appendix, a 168 unit or stack operating 

hour grace period is available for 

quarterly linearity checks, and a 720 

unit or stack operating hour grace 

period is available for RATAs, as 

provided, respectively, in sections 2.2.4 

and 2.3.3 of appendix B to part 75 of 

this chapter. 

5.4.2.2 For the purposes of this 

appendix, if the deadline for a required 

gas audit/data accuracy assessment or 

RATA of an HCl CEMS cannot be met 

due to circumstances beyond the control 

of the owner or operator: 

5.4.2.2.1 A 168 unit or stack 

operating hour grace period is available 

in which to perform the gas audit or 

other quarterly data accuracy 

assessment; or 

5.4.2.2.2 A 720 unit or stack 

operating hour grace period is available 

in which to perform the RATA. 

5.4.2.3 If a required QA test is 

performed during a grace period, the 

deadline for the next test shall be 

determined as follows: 

5.4.2.3.1 For a gas audit or RATA of 

the monitoring systems described in 

sections 5.1 and 5.2 of this appendix, 

determine the deadline for the next gas 

audit or RATA (as applicable) in 

accordance with section 2.2.4(b) or 

2.3.3(d) of appendix B to part 75 of this 

chapter; treat a gas audit in the same 

manner as a linearity check. 

5.4.2.3.2 For the gas audit or other 

quarterly data accuracy assessment of an 

HCl or HF CEMS, the grace period test 

only satisfies the audit requirement for 

the calendar quarter in which the test 

was originally due. If the calendar 

quarter in which the grace period audit 

is performed is a QA operating quarter, 

an additional gas audit/data accuracy 

assessment is required for that quarter. 

5.4.2.3.3 For the RATA of an HCl or 

HF CEMS, the next RATA is due within 

three QA operating quarters after the 

calendar quarter in which the grace 

period test is performed. 

5.4.3 Conditional Data Validation. 

For recertification and diagnostic testing 

of the monitoring systems that are used 

to provide data under this appendix, the 

conditional data validation provisions 

in § 75.20(b)(3)(ii) through (ix) of this 

chapter may be used to avoid or 

minimize data loss. The allotted 

window of time to complete calibration 

tests and RATAs shall be as specified in 

§ 75.20(b)(3)(iv) of this chapter; the 

allotted window of time to complete a 

quarterly gas audit or data accuracy 

assessment shall be the same as for a 

linearity check (i.e., 168 unit or stack 

operating hours). 

* * * * * 

8. QA/QC Program Requirements 

The owner or operator shall develop 

and implement a quality assurance/

quality control (QA/QC) program for the 

HCl and/or HF CEMS that are used to 

provide data under this subpart. At a 

minimum, the program shall include a 

written plan that describes in detail (or 

that refers to separate documents 

containing) complete, step-by-step 

procedures and operations for the most 

important QA/QC activities. Electronic 

storage of the QA/QC plan is 

permissible, provided that the 

information can be made available in 

hard copy to auditors and inspectors. 

The QA/QC program requirements for 


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the other monitoring systems described 

in section 5.3 of this appendix are 

specified in section 1 of appendix B to 

part 75 of this chapter. 

* * * * * 

9. Data Reduction and Calculations 

* * * * * 

9.3.2 For gross output-based 

emission rates, first calculate the HCl or 

HF mass emission rate (lb/h), using an 

equation that has the general form of 

Equation A–2 or A–3 in appendix A to 

this subpart (as applicable), replacing 

the value of K with 9.43 × 10¥8 lb/scfppm (for HCl) or 5.18 × 10¥8 (for HF) 

and defining Ch as the hourly average 

HCl or HF concentration in ppm. Then, 

divide the result by the hourly gross 

output (megawatts) to convert it to units 

of lb/MWh. If the gross output is zero 

during a startup or shutdown hour, use 

the default gross output (as defined in 

§ 63.10042) to calculate the HCl or HF 

emission rate. The default gross output 

is not considered to be a substitute data 

value. 

* * * * * 

[FR Doc. 2016–06563 Filed 4–5–16; 8:45 am] 

BILLING CODE 6560–50–P 


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