Vol. 80 Tuesday, 

No. 31 February 17, 2015 

Part III 

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; Revisions; Proposed Rule 


tkelley on DSK3SPTVN1PROD with PROPOSALS3
8442 Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 60 and 63 

[EPA–HQ–OAR–2009–0234 and EPA–HQ– 

OAR–2011–0044; FRL–9921–04–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; Revisions 

AGENCY: Environmental Protection 

Agency. 

ACTION: Proposed rule. 

SUMMARY: The U.S. Environmental 

Protection Agency (EPA) is proposing 

this action to correct and clarify certain 

text of the final action titled ‘‘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,’’ 

which was published in the Federal 

Register of Thursday, February 16, 

2012. We are also proposing to remove 

rule provisions establishing an 

affirmative defense for malfunction 

events in light of a recent court decision 

on the issue. 

DATES: Comments. Comments must be 

received on or before April 3, 2015. 

Public Hearing. If anyone contacts the 

EPA requesting a public hearing by 

February 23, 2015, the EPA will hold a 

public hearing on March 4, 2015 from 

1 p.m. (Eastern Standard Time) to 5 p.m. 

(Eastern Standard Time) at the U.S. 

Environmental Protection Agency 

building located at 109 T.W. Alexander 

Drive, Research Triangle Park, NC 

27711. If the EPA holds a public 

hearing, the EPA will keep the record of 

the hearing open for 30 days after 

completion of the hearing to provide an 

opportunity for submission of rebuttal 

and supplementary information. 

ADDRESSES: Submit your comments, 

identified by Docket ID. No. EPA–HQ– 

OAR–2011–0044 (NSPS action) or 

Docket ID No. EPA–HQ–OAR–2009– 

0234 (NESHAP/MATS action), by one of 

the following methods: 

• Federal rulemaking portal: http://

www.regulations.gov. Follow the 

instructions for submitting comments. 

• Agency Web site: http://

www.epa.gov/oar/docket.html. Follow 

the instructions for submitting 

comments on the EPA Air and Radiation 

Docket Web site. 

• Email: Comments may be sent by 

electronic mail (email) to a-and-rdocket@epa.gov, Attention EPA–HQ– 

OAR–2011–0044 (NSPS action) or EPA– 

HQ–OAR–2009–0234 (NESHAP/MATS 

action). 

• Fax: Fax your comments to: (202) 

566–9744, Docket ID No. EPA–HQ– 

OAR–2011–0044 (NSPS action) or 

Docket ID No. EPA–HQ–OAR–2009– 

0234 (NESHAP/MATS action). 

• Mail: Send your comments on the 

NESHAP/MATS action to: EPA Docket 

Center (EPA/DC), Environmental 

Protection Agency, Mailcode: 28221T, 

1200 Pennsylvania Ave. NW., 

Washington, DC 20460, Docket ID No. 

EPA–HQ–OAR–2009–0234. Send your 

comments on the NSPS action to: EPA 

Docket Center (EPA/DC), Environmental 

Protection Agency, Mailcode: 2822T, 

1200 Pennsylvania Ave. NW., 

Washington, DC 20460, Docket ID. No. 

EPA–HQ–OAR–2011–0044. 

• Hand Delivery or Courier: Deliver 

your comments to: EPA Docket Center, 

EPA WJC West Building, Room 3334, 

1301 Constitution Ave. NW., 

Washington, DC 20460. Such deliveries 

are only accepted during the Docket’s 

normal hours of operation (8:30 a.m. to 

4:30 p.m., Monday through Friday, 

excluding legal holiday), and special 

arrangements should be made for 

deliveries of boxed information. 

FOR FURTHER INFORMATION CONTACT: For 

the NESHAP action: Mr. Barrett Parker, 

Measurement Policy Group, Sector 

Policies and Programs Division, (D243– 

05), Office of Air Quality Planning and 

Standards, U.S. Environmental 

Protection Agency, Research Triangle 

Park, North Carolina 27711; Telephone 

number: (919) 541–5635; Fax number 

(919) 541–3207; email address: 

parker.barrett@epa.gov. For 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: 

Comment Instructions. All 

submissions must include agency name 

and respective docket number or 

Regulatory Information Number (RIN) 

for this rulemaking. All comments will 

be posted without change and may be 

made available online at http://

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be confidential business 

information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http://

www.regulations.gov or email. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means the EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to the EPA without 

going through http://

www.regulations.gov, your email 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, the EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If the EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, the EPA may not 

be able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. 

Public Hearing. If requested by 

February 23, 2015, we will hold a public 

hearing on March 4, 2015, from 1 p.m. 

(Eastern Standard Time) to 5 p.m. 

(Eastern Standard Time) at the U.S. 

Environmental Protection Agency 

building located at 109 T.W. Alexander 

Drive, Research Triangle Park, NC 

27711. Please contact Ms. Pamela 

Garrett of the Sector Policies and 

Programs Division (D243–01), Office of 

Air Quality Planning and Standards, 

Environmental Protection Agency, 

Research Triangle Park, NC 27711; 

telephone number: 919–541–7966; 

email address: garrett.pamela@epa.gov; 

to request a hearing, register to speak at 

the hearing or to inquire as to whether 

or not a hearing will be held. The last 

day to pre-register in advance to speak 

at the hearing will be March 2, 2015. 

Additionally, requests to speak will be 

taken the day of the hearing at the 

hearing registration desk, although 

preferences on speaking times may not 

be able to be fulfilled. If you require the 

service of a translator or special 

accommodations such as audio 

description, we ask that you pre-register 

for the hearing, as we may not be able 

to arrange such accommodations 

without advance notice. The hearing 

will provide interested parties the 


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Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 8443 

opportunity to present data, views or 

arguments concerning the proposed 

action. The EPA will make every effort 

to accommodate all speakers who arrive 

and register. Because this hearing is 

being held at a U.S. government facility, 

individuals planning to attend the 

hearing should be prepared to show 

valid picture identification to the 

security staff in order to gain access to 

the meeting room. Please note that the 

REAL ID Act, passed by Congress in 

2005, established new requirements for 

entering federal facilities. If your 

driver’s license is issued by Alaska, 

American Samoa, Arizona, Kentucky, 

Louisiana, Maine, Massachusetts, 

Minnesota, Montana, New York, 

Oklahoma or the State of Washington, 

you must present an additional form of 

identification to enter the federal 

building. Acceptable alternative forms 

of identification include: Federal 

employee badges, passports, enhanced 

driver’s licenses and military 

identification cards. In addition, you 

will need to obtain a property pass for 

any personal belongings you bring with 

you. Upon leaving the building, you 

will be required to return this property 

pass to the security desk. No large signs 

will be allowed in the building, cameras 

may only be used outside of the 

building and demonstrations will not be 

allowed on federal property for security 

reasons. The EPA may ask clarifying 

questions during the oral presentations, 

but will not respond to the 

presentations at that time. Written 

statements and supporting information 

submitted during the comment period 

will be considered with the same weight 

as oral comments and supporting 

information presented at the public 

hearing. Verbatim transcripts of the 

hearing and written statements will be 

included in the docket for the 

rulemaking. The EPA will make every 

effort to follow the schedule as closely 

as possible on the day of the hearing; 

however, please plan for the hearing to 

run either ahead of schedule or behind 

schedule. Again, a hearing will not be 

held on this rulemaking unless 

requested. A hearing needs to be 

requested by February 23, 2015. Again, 

please contact Ms. Pamela Garrett of the 

Sector Policies and Programs Division 

(D243–01), Office of Air Quality 

Planning and Standards, Environmental 

Protection Agency, Research Triangle 

Park, NC 27711; telephone number: 

919–541–7966; email address: 

garrett.pamela@epa.gov to request a 

hearing. 

Docket. All documents in the docket 

are listed in the http://

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available (e.g., CBI or other 

information whose disclosure is 

restricted by statute). Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy 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, 

1301 Constitution Avenue NW., 

Washington, DC. The Public Reading 

Room is open from 8:30 a.m. to 4:30 

p.m., Monday through Friday, excluding 

legal holidays. The telephone number 

for the Public Reading Room is (202) 

566–1744, and the telephone number for 

the Air Docket is (202) 566–1742. 

I. Technical Corrections 

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 ‘‘the Mercury and Air Toxics 

Standards’’ or ‘‘MATS,’’ and new source 

performance standards (NSPS) for fossilfuel-fired electric utility, industrialcommercial-institutional, and small 

industrial-commercial-institutional 

steam generating units, referred to as the 

Utility NSPS. 

In this document, the EPA proposes to 

correct certain regulatory text. The 

proposed corrections can be categorized 

generally as follows: (a) Resolution of 

conflicts between preamble and 

regulatory text, (b) corrections that we 

stated we would make in response to 

comments that were inadvertently not 

made, and (c) clarification of language 

in regulatory text. Below, we identify 

each proposed technical correction to 

the regulatory text as found in the Code 

of Federal Regulations (i.e., 40 CFR). 

The EPA is soliciting comments on all 

of these proposed corrections. 

1. Section 60.49Da(f) is revised to 

amend the procedures for calculating 

compliance with the NSPS daily average 

particulate matter (PM) emission limit 

for affected facilities using PM 

continuous emission monitoring 

systems (CEMS) and that commenced 

construction, modification, or 

reconstruction before May 4, 2011. Even 

though it was not included in the 

proposal, in an effort to clarify certain 

language in 40 CFR 60.48Da(f), we 

amended the procedure for calculating 

compliance with the daily average PM 

limit for affected facilities for which 

construction, modification, or 

reconstruction commenced before May 

4, 2011, using PM CEMS (78 FR 24073; 

April 24, 2013). The amendments 

removed the provision that for operating 

days with less than 18 hours of PM 

CEMS data, the data for that day would 

be rolled into the following operating 

day(s) until 18 hours of data are 

available. The intent of the original 

language was to assure that compliance 

with the daily PM emission rate was not 

determined with significantly less than 

24 hours of data, but that all emissions 

data would still be used. The intent of 

the revised data was to eliminate the 

requirement to roll emissions data 

recorded on days without sufficient data 

to determine a daily average to the 

following operating day, but that a 

minimum of 18 hours would still be 

required to determine compliance with 

the daily PM standard. Industry 

requested reconsideration stating that 

they did not have an opportunity to 

comment on the issue, and that the 

revised calculation procedures could in 

fact require compliance determinations 

with significantly less than 24 hours of 

data. The proposed revisions would 

undo those changes and return the 

calculation procedures to the approach 

used prior to April 24, 2013. 

Specifically, for operating days with less 

than 18 hours of PM CEMS data, that 

data would be rolled into the following 

operating day(s) until over 18 hours of 

data are available to determine 

compliance with the operating day 

standard. We are soliciting comment on 

whether the intent of the current 

calculation procedures should be 

maintained (i.e., data collected on days 

with less than 18 hours of data would 

not be used to determine compliance 

with the PM standard and would also 

not be rolled into the following 

operating day(s)). If the current 

approach is maintained, the regulatory 

language would be revised to avoid 

situations where compliance 

calculations would be made with less 

than 18 hours of data. 

2. Section 63.9983(a) is revised to 

clarify that MATS does not apply to 

either major or area source combustion 

turbines, except for integrated 

gasification combined cycle (IGCC) 

units. In the final MATS rule, 40 CFR 

63.9983(a) exempted from MATS ‘‘any 

unit designated as a stationary 

combustion turbine, except an 

integrated gasification combined cycle 

(IGCC) unit, covered by 40 CFR part 63, 

subpart YYYY.’’ Because area source 

stationary combustion turbines are not 

subject to subpart YYYY, which is 

applicable to stationary combustion 

turbines located at major sources, the 

Agency received questions concerning 

the applicability of MATS to the area 


tkelley on DSK3SPTVN1PROD with PROPOSALS3
8444 Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 

1Prepublication version found at http://

www.epa.gov/ttn/atw/boiler/boilerpg.html. The 

prepublication version will be replaced with the 

Federal Register document when the proposal is 

published. 

2To the extent these EGUs bypassed their control 

devices without measuring emissions, the hours of 

bypass operation would need to be reported as 

hours of monitoring deviation and subject to 

potential enforcement action. 

source units in that category. The EPA 

intended by the exemption to exempt all 

stationary source combustion turbines 

other than IGCC units from the 

requirements of MATS, because the EPA 

does not interpret the statute to include 

those units within the definition of EGU 

in CAA section 112(a)(8). The proposed 

revisions to the regulations will clarify 

the EPA’s interpretation and intent and 

prevent future confusion concerning the 

applicability of the MATS rule to 

stationary combustion turbines located 

at area sources. 

3. Section 63.9983(b) and (c) is 

revised consistent with the definitional 

changes discussed below. The 

definitional changes are being proposed 

so that sources will know the time 

period to consider when determining 

whether their coal or oil utilization 

triggers applicability of the MATS rule. 

As explained below, the change is 

particularly important in the first 3 

years after the compliance date when 

sources will be required to estimate coal 

and oil utilization in their EGUs to 

determine applicability of the MATS 

rule. 

4. Section 63.9983(e) is added to 

clarify CAA section 112 applicability to 

the units that meet 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 (40 CFR 

part 63, subpart DDDDD). These 

overlapping definitions led to confusion 

in the regulated community about 

whether such units are natural gas-fired 

EGUS pursuant to MATS or biomassfired boilers subject to the Industrial 

Boiler NESHAP. We are revising the 

MATS rule to make clear that such units 

are biomass-fired boilers subject to the 

industrial boiler NESHAP. Similar 

revisions to the applicability provisions 

of the Industrial Boiler NESHAP have 

been proposed.1

5. Section 63.9991(c)(1) and (2) is 

being revised to clarify the conditions 

that are required in order to use the 

alternate sulfur dioxide (SO2) limit. 

6. Sections 63.10000(c)(1)(i)(A) and 

63.10005(h) are revised to clarify the 

provisions of units designated as being 

low emitting EGUs (LEE) when an acid 

gas scrubber and a bypass stack are 

present. 

7. Section 63.10000(c)(1)(i)(C) is 

added to allow EGUs the ability to seek 

LEE status if their bypass stacks vent 

through stacks that are able to measure 

emissions. In addition, the proposed 

language would allow EGUs with LEE 

status the ability to bypass emissions 

control devices during emergency 

periods provided certain fuel and time 

restrictions, along with notification 

requirements, occur. 

The final MATS rule did not allow 

EGUs whose emissions control devices 

had bypasses to seek LEE status. Owners 

and operators of EGUs whose emissions 

control devices had no bypass stacks, 

but instead routed bypass emissions 

through main stacks equipped with 

emissions measurement capability, 

requested that we allow their EGUs to 

seek LEE status provided emissions 

were measured during bypass events. 

We believe that EGU owners or 

operators that have the ability to 

measure and report emissions during 

bypass events should be able to seek 

LEE status as long as bypass emissions 

are included in the calculations 

required to demonstrate the LEE status 

eligibility. For this reason, we are 

proposing to allow this option. 

Also, a number of EGU owners or 

operators requested that we allow EGUs 

with LEE status the ability to bypass 

their emissions control devices in 

emergency conditions, provided that the 

EGUs were combusting clean fuels and 

that the bypass periods were of short 

duration.2 We reviewed the requests 

and believe that control device bypass 

operation for up to 2 percent of EGU 

operating hours while combusting clean 

fuel during emergency periods is 

reasonable, provided a report detailing 

the emergency event, its cause, the 

corrective action taken to alleviate the 

emergency event, and estimates of the 

emissions released during the 

emergency event are provided. In 

addition, an EGU owner or operator 

must include these emergency 

emissions along with performance test 

results in assessing whether its EGU 

maintains LEE status. We seek comment 

on the adequacy of the restrictions 

associated with bypass conditions 

regarding maintaining LEE status. 

8. Section 63.10000(c)(2)(iii) is 

revised to state that EGU owners or 

operators who choose to use quarterly 

testing and parametric monitoring for 

hydrogen fluoride (HF) or hydrogen 

chloride (HCl) compliance must include 

the continuous monitoring systems 

(CMS) that will be used in their sitespecific monitoring plans to comply 

with the monitoring requirements. 

9. Section 63.10000(m) is added 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 to generate data to meet the work 

practice standards. Moreover, this 

addition clarifies that those monitoring 

systems may be installed, verified, 

operated, maintained, and quality 

assured using manufacturer’s 

specifications. 

10. Section 63.10001 is revised to 

remove the affirmative defense 

provisions as explained in Section II 

below. The section is reserved. 

11. Section 63.10005(a) is revised 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. 

12. Section 63.10005(a)(2) is revised 

to clarify the date by which compliance 

must be demonstrated for EGUs using 

CMS or sorbent trap monitoring 

systems. 

13. Section 63.10005(a)(2)(i) is revised 

to clarify applicability of the provision 

to both the 30- and 90-boiler operating 

day performance testing requirements. 

14. Section 63.10005(b)(1) is revised 

to clarify the time period allowed for 

existing EGUs to use stack test data 

collected prior to the applicable 

compliance date. 

15. Section 63.10005(b)(6) is added 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 the initial 

performance test requirement. 

16. Section 63.10005(d)(3) and 

(d)(4)(i) is revised to more clearly state 

when compliance must be 

demonstrated. 

17. Section 63.10005(f) is revised to 

clarify when sources must complete the 

initial boiler tune-up after the 

compliance date, and the timing for 

subsequent tune-ups when a tune-up 

conducted prior to the compliance date 

is used to satisfy the initial tune-up 

requirement. 

18. Section 63.10005(h)(3) is revised 

to clarify that the alternate 30- and 90- 

day averaging provisions are both 

applicable to mercury (Hg) emission 

limits, and to clarify the sampling probe 

location. 

19. Section 63.10005(i)(4) is revised to 

delete paragraphs (iii) and (iv). The 

identified test methods contain 

requirements for fuel sampling, not 

determining fuel moisture content, as 

required in the provision. 


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Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 8445 

20. Section 63.10006(f) is revised to 

specify EGU operational status with 

respect to performance testing; to 

identify the requirements—including 

make-up testing and reporting—if the 

performance testing schedule is missed 

apart from using existing skip 

procedures; and to identify intervals 

between performance tests. The final 

MATS rule had no provision that 

allowed an EGU owner or operator to 

skip a required performance test if its 

EGU was otherwise not operating; we 

did not believe the rule needed to be 

explicit in stating that EGUs need not be 

turned on solely to conduct 

performance testing. However, we have 

received questions regarding this 

circumstance. We believe it is 

appropriate to allow an EGU owner or 

operator the ability to skip a required 

performance test if its EGU is not 

otherwise operating, and are proposing 

this in this action. The final MATS rule 

had no provisions regarding make-up 

testing and reporting should a regularly 

scheduled performance test be missed 

for reasons other than the existing skip 

procedures. We believe it is appropriate 

to specify a schedule for required makeup testing and reporting, and are 

proposing such a schedule in this 

action. The final MATS rule specified 

the time periods between performance 

tests, but EGU owners or operators 

expressed concerns about being able to 

adhere to such a schedule. We believe 

their concerns about having too tight a 

timeline for retesting to occur and our 

concern about having a sufficient 

interval of time between tests such that 

the results better reflect characteristics 

of different periods can be addressed by 

specifying a minimum interval of time 

between subsequent performance tests, 

which we are proposing in this action. 

We welcome comments as to the need 

for, as well as efficacy of, these 

proposed revisions, as well as on these 

proposed intervals. 

21. Section 63.10009(a)(2) and (a)(2)(i) 

is revised to clarify that the 90-boiler 

operating day averaging period is 

available as an option for Hg emissions 

from non-low rank virgin coal-fired 

EGUs (i.e., EGUs in the subcategory 

‘‘unit designed for coal ≥8,300 Btu/lb’’). 

In the final MATS (77 FR 9303 at 9385), 

we had indicated that we were 

providing the 90-boiler operating day 

averaging period as an alternative 

compliance approach (to the standard 

30-boiler operating day averaging 

period) for Hg emissions from EGUs in 

that subcategory. However, the 

regulatory text in 40 CFR 63.10009(a)(2) 

did not clearly reflect this option. 

The term ‘‘gross electric output’’ is 

also corrected to ‘‘gross output’’ which 

is the term defined in 40 CFR 63.10042. 

22. Section 63.10009(b)(1) is revised 

to clarify group eligibility equations 1a 

and 1b. These equations were developed 

to provide EGU owners or operators a 

quick method for determining if their 

emissions averaging group could meet 

the emissions limit when operated at 

the maximum rated heat input and, in 

some cases, steam production. 

Commenters reported difficulty in using 

the equations in the final rule, so the 

equations have been revised so that 

individual EGU characteristics, whether 

from CEMS or stack testing results, are 

easier to input. We request comment on 

the proposed revisions concerning their 

usefulness in calculating the maximum 

potential emissions rate from an 

emissions averaging group. The term 

‘‘gross electric output’’ is also corrected 

to ‘‘gross output’’ which is the term 

defined in 40 CFR 63.10042. 

23. Section 63.10009(b)(2) and (3) is 

revised to correct the term ‘‘gross 

electric output’’ to ‘‘gross output’’ which 

is the term defined in 40 CFR 63.10042. 

24. Section 63.10009(f) is revised 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. Instead of relying on the 

maximum normal operating load of each 

EGU in determining the ability of the 

emissions averaging group to 

demonstrate initial compliance, as was 

contained in the final MATS rule, we 

are proposing in this action to use the 

maximum possible heat input or gross 

output of each EGU in determining the 

ability of the emission averaging group 

to demonstrate initial compliance. In 

addition, instead of calculating the 

maximum weighted average emissions 

rate, as used in the final MATS rule, we 

are proposing in this action to calculate 

the initial weighted average emissions 

rate. Finally, instead of specifying just 

one date for submitting an emissions 

averaging plan, as was done in the final 

MATS rule, we are proposing in this 

action to allow an EGU owner or 

operator the flexibility to choose other 

dates to begin using an emissions 

averaging plan by allowing the 

submission of an emissions averaging 

plan at least 120 days before the date on 

which emissions averaging is to begin. 

We believe these changes will provide 

additional flexibility without 

undermining the enforceability of the 

final standards. 

25. Section 63.10009(f)(2), (g)(1), 

(g)(2), and (j)(1)(ii) is revised to correct 

the term ‘‘gross electric output’’ to 

‘‘gross output’’ which is the term 

defined in 40 CFR 63.10042. 

26. Section 63.10010(a)(4) is revised 

to add a 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. 

27. Section 63.10010(f)(3) is revised to 

clarify that 30-boiler operating day 

rolling averages are to be based only on 

valid hourly SO2 emission rates. 

28. Section 63.10010(h)(6)(i) and (ii), 

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

is revised 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. The final 

MATS rule established that all data 

collected with PM CPMS, PM CEMS, 

and HAP metals CEMS during all boiler 

operating hours were to be used in 

assessing compliance except those data 

collected during monitoring system 

malfunctions, repairs associated with 

monitoring system malfunctions, 

required quality assurance or quality 

control activities, or monitoring out-ofcontrol periods. In addition, the final 

MATS rule sections combined the 

requirement to report the periods when 

data collected during these operating 

periods as deviations into one long 

sentence. In this action, we are 

proposing to separate these 

requirements into two sentences to ease 

readability. 

29. Section 63.10010(l)(i) is revised to 

replace the incorrect reference to 

§ 63.7(e) with the correct reference to 

§ 63.8(d)(2). 

30. Section 63.10010(l) and (l)(4) is 

revised 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 to generate 

data to meet the work practice 

standards. Moreover, this revision 

clarifies that those monitoring systems 

may be installed, verified, operated, 

maintained, and quality assured using 

manufacturer’s specifications. 

31. Section 63.10011(b) is revised to 

remove the incorrect reference to Table 

4 and to replace the incorrect reference 

to Table 7 with the correct reference to 

Table 6. 

32. Section 63.10011(c)(1) and (2) is 

revised to clarify the date by which 

compliance must be demonstrated by 

EGUs that use CEMS or sorbent trap 

monitoring systems. In addition, 

§ 63.10011(c)(1) is revised to clarify that 


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3See the description of the ‘‘third approach’’ at 

79 FR 24708 (April 24, 2013). 

the alternate Hg emission limit may be 

used. 

33. Section 63.10011(e) is revised to 

replace ‘‘according to’’ with ‘‘in 

accordance with.’’ 

34. Section 63.10011(g)(4)(v)(A) and 

Table 3 are revised to clarify our intent 

regarding clean fuel use ‘‘to the 

maximum extent possible.’’ Our goal in 

the work practice is to minimize HAP 

emissions during startup and shutdown 

periods, and that goal can be 

accomplished by minimizing primary 

fuel use and maximizing clean fuel use 

because of the inherently low HAP 

content of the defined ‘‘clean fuels.’’ As 

stated in the preamble to the final 

startup and shutdown reconsideration 

rule, EGUs that chose to comply with 

the alternative work practice will be 

required to have sufficient clean fuel 

capacity to startup and warm the facility 

to the point where the primary PM 

controls can be brought on line at the 

same time as, or within 1 hour of, the 

addition of the primary fuel to the EGU. 

79 FR 68777 at 68779, November 19, 

2014. We recognize that the clean fuel 

requirement may require sources to 

increase clean fuel capacity, modify the 

startup burners, and/or take additional 

actions to comply with the final rule. 79 

FR 68777 at 68779, November 19, 2014. 

Thus, we expect clean fuels to be 

combusted in at least the amount 

needed to bring the emissions control 

devices to operational levels necessary 

to comply with the numeric standards at 

the end of startup. We do not expect 

clean fuel use to the extent that it 

compromises the integrity of the boiler 

or its control devices; neither do we 

expect clean fuel to be combusted in 

excess of the amount needed to bring 

the emissions control devices to 

expected operational levels. We have 

determined that it is appropriate to 

slightly revise the language in the 

November 19, 2014, final rule. 79 FR 

68777. The proposed revision would 

change the language from ‘‘to the 

maximum extent possible’’ to ‘‘to the 

maximum extent practicable, taking into 

account boiler or control device 

integrity.’’ 

35. Section 63.10020(e) is revised to 

clarify that it applies only to those 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’’ in § 63.10020(e)(3)(i)(E) have 

been replaced with the correct terms 

‘‘liquid to flue gas ratio’’ and ‘‘the 

pressure drop across the scrubber.’’ 

Finally, in order to clarify our intent 

that existing instrumentation or 

engineering calculations can be used to 

provide flow information, 

§ 63.10020(e)(3)(i)(A) and (B) is revised 

to remove the term ‘‘rate’’ and to 

acknowledge the use of existing 

combustion air flow monitors or 

combustion equations. 

36. Section 63.10021(d)(3) is revised 

to clarify the type of monitoring that is 

to be used to demonstrate compliance. 

37. Section 63.10021(e) is revised to 

clarify the condition that allows delay of 

burner inspections for initial boiler 

tune-ups. 

38. Section 63.10021(e)(9)(i) and (ii) is 

revised to clarify the dates that tune-ups 

must be reported. 

39. Section 63.10023(b) and Table 6 

are revised 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. The final rule allowed existing 

EGUs to determine the operating limit 

based on the highest 1-hour average PM 

CPMS value recorded during a 

performance test, even if that average 

time was associated with a test run in 

excess of the numeric standards, while 

new EGUs were required to use a 

scaling factor or the average PM CPMS 

value recorded during the PM 

compliance test demonstrating 

compliance with the PM limit to 

establish the operating limit.3 We 

believe all EGUs should use a consistent 

set of procedures for both new and 

existing EGUs for establishing an 

operating PM limit, so we are proposing 

in this action to revise the procedures 

for existing EGUs. The procedures for 

existing EGUs, contained in 

§ 63.10023(b)(1) are reserved, and 

§ 63.10023(b)(2) and Table 6 are revised 

so that all EGUs are to follow the 

operating limit development procedures 

for new EGUs (i.e., use a scaling factor 

or the average PM CPMS value recorded 

during the PM compliance test 

demonstrating compliance with the PM 

limit to establish the operating limit). 

40. Section 63.10030(e)(1) is revised 

to replace the phrase ‘‘identification of 

which subcategory the source is in’’ 

with ‘‘identification of the subcategory 

of the source.’’ 

41. Section 63.10030(e)(7)(i) is revised 

to clarify that the date of each stack test 

conducted for purposes of 

demonstrating LEE eligibility is to be 

provided. The final rule establishes that 

each test for pollutants other than Hg 

conducted over a 3-year period must 

meet the LEE emission limit in order for 

an EGU to be eligible for LEE status. 

42. Section 63.10030(e)(7)(iii) is 

added 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. 

The EPA has received questions about 

how frequently an existing EGU could 

alternate between the two compliance 

formats. Although we did not envision 

that an owner or operator of an existing 

EGU would want to change the basis of 

the EGU’s emission limits, we believe it 

is reasonable to allow such action 

provided certain conditions, including 

performance testing demonstrating 

compliance with the new format, 

submission of a written request to 

change formats, and receipt of 

permission from the Administrator to 

change formats, are met. We request 

comment on these procedures, as well 

as on the concept of switching emission 

limits, particularly during performance 

averaging periods. 

43. Section 63.10030(e)(8)(i) is revised 

to clarify that it applies only to those 

EGU owners or operators who choose to 

meet the work practice standards 

contained in paragraph (2) of the 

definition of startup. Moreover, the 

provisions requiring a description of PM 

control device efficiencies and PM 

emission rates are revised to clarify that 

such efficiencies and emission rates are 

those of periods other than startup and 

shutdown periods. As the uncontrolled 

emission rates can be calculated from 

control device efficiencies and 

corresponding emission rates, the 

provisions requiring reporting of 

uncontrolled emission rates have been 

removed. 

In addition, as current EGU 

characteristics are most relevant for 

compliance with the MATS rule, the 

requirements concerning identification 

of intermediate changes to the EGU 

design have been removed. In order to 

reduce redundant reporting, the rule has 

been revised to require no additional 

identification if no changes to the EGU’s 

design characteristics have occurred. 

Finally, § 63.10030(e)(8)(ii)(A) has 

been revised to remove the requirement 

for use of an independent professional 

engineer. Consistent with the discussion 

contained in 71 FR 16869 (April 4, 

2006), we believe that a professional 

engineer, regardless of whether they are 

independent, is able to give a fair 

technical review because of the 

programs established by the state 

licensing boards, which serve to enforce 

objectivity from each registrant. We 

believe that the revision will allow 

EGUs to reduce burden without 

compromising environmental safety by 


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using in-house expertise. Professional 

engineers employed by an EGU should 

be more familiar with its design and 

operational characteristics and should 

be in a position to expedite collection 

and submission of required information. 

44. Section 63.10030(f) is revised to 

add notification requirements for EGUs 

that move in and out of MATS 

applicability. 

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

to clarify the reporting requirements for 

EGU tune-ups. 

46. Section 63.10031(c)(5) is revised 

to clarify that it applies only to those 

EGU owners or operators who choose to 

meet the work practice standards 

contained in paragraph (2) of the 

definition of startup. 

47. Section 63.10031(c)(6) is revised 

to add emergency bypass reporting for 

EGUs with LEE status. 

48. Section 63.10031(f)(5) is revised to 

state that the Administrator retains the 

right to require submittal of reports 

subject to paragraph (f)(4), as well as 

paragraphs (f)(1) through (3). 

49. Section 63.10032(f) is revised 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. 

50. The definitions of ‘‘Coal-fired 

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,’’ ‘‘Natural gas-fired electric 

utility steam generating unit,’’ and ‘‘Oilfired electric utility steam generating 

unit’’ in § 63.10042 are revised to clarify 

the period of time to be included in 

determining the source’s applicability to 

the MATS. 

During the comment period on the 

proposed MATS rule, industry noted 

that many EGUs would convert to 

natural gas or other non-fossil fuel prior 

to the compliance date and those 

sources would remain subject to MATS 

because the proposed rule required 

sources to determine applicability based 

on the 3 calendar years prior to the 

compliance date. See, e.g., 40 CFR 

63.10042 (definition of ‘‘fossil fuelfired’’). The EPA agreed that this was 

not the EPA’s intent and in the final 

MATS rule revised several definitions, 

including the definition of fossil fuelfired, that required sources to evaluate 

usage after the applicable compliance 

date. 

The EPA inadvertently created 

confusion in its attempt to address 

industry concerns in the final MATS 

rule. The confusion is best illustrated by 

an analysis of the proposed and final 

definitions of ‘‘fossil fuel-fired.’’ The 

EPA’s proposed definition stated, in 

part, that ‘‘[i]n addition, fossil fuel-fired 

means any EGU that fired fossil fuel for 

more than 10.0 percent of the average 

annual heat input during the previous 3 

calendar years or for more than 15.0 

percent of the annual heat input during 

any one of those calendar year.’’ See 76 

FR 24975 at 25123 (emphasis added). 

The intent in this definition was to 

require sources to look at the usage from 

the 3 previous years to determine if the 

average or the single year usage from 

those 3 years exceeded either of the 

thresholds. 

To address the commenters’ concern, 

the EPA revised the definition of ‘‘fossil 

fuel-fired’’ in the final rule to state, in 

part, that ‘‘[i]n addition, fossil fuel-fired 

means any EGU that fired fossil fuels for 

more than 10.0 percent of the average 

annual year input during any 3 

consecutive calendar years or for more 

than 15.0 percent of the annual heat 

input during any one calendar year after 

the applicable compliance date.’’ 40 

CFR 63.10042 (emphasis added). This 

definition creates at least two potential 

compliance issues: (1) It creates 

confusion as to how sources are to 

determine MATS applicability during 

the first 3 years after the applicable 

compliance date; and (2) it subjects 

sources to MATS in perpetuity if the 

usage thresholds are ever exceeded after 

the compliance date—‘‘any 3 

consecutive calendar years’’ or ‘‘any one 

calendar year’’ ‘‘after the applicable 

compliance date.’’ 

The proposed revisions to the 

definitions address both issues. 

Concerning applicability in the first 3 

years after the applicable compliance 

date, this proposed rule states that 

sources must project their coal and oil 

usage for the first 3 years to determine 

whether the EGU will exceed either the 

10.0 or 15.0 percent threshold. The 

EPA’s understanding is that sources 

know with sufficient specificity the 

fuels they will use in advance, and 

requiring sources to project their usage 

accommodates industry concerns that 

the sources that are converting to 

natural gas or biomass prior to the 

compliance date not be subject to 

MATS. 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. 

The EPA is also proposing to revise 

the definitions to 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 

calendar years on an annual rolling 

basis, consistent with the definition of 

‘‘fossil fuel-fired’’ proposed in the 

MATS rule. This proposed change will 

prevent EGUs from being subject to 

MATS in perpetuity if they exceed the 

10 or 15 percent threshold at any time 

after the compliance date. 

A definition of ‘‘neural network’’ is 

also being 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. 

51. Table 1 to subpart UUUUU of Part 

63 is revised to correct the term ‘‘gross 

electric output’’ to ‘‘gross output’’ which 

is the term defined in 40 CFR 63.10042 

in footnotes 1, 4, and 5. 

52. Table 2 to subpart UUUUU of Part 

63 is revised to correct the term ‘‘gross 

electric output’’ to ‘‘gross output’’ which 

is the term defined in 40 CFR 63.10042 

in footnote 2. 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. 

53. Table 3 to subpart UUUUU of Part 

63 is revised as described earlier to 

clarify the term ‘‘maximum extent 

possible.’’ 

In addition, we have received 

questions concerning the interpretation 

of the definition of startup, particularly 

the language defining the end of startup. 

Industry has inquired whether the 

triggering action is either the generation 

of electricity or of steam for any useful 

purpose under both definitions of 

startup. The EPA does interpret the end 

of startup in a consistent manner as 

between the two definitions. 

Specifically, we interpret the phrase 

‘‘. . . when any of the steam from the 

boiler is used . . . for any other 

purpose,’’ contained in paragraph (1) of 

the definition of startup, to have the 

same meaning as the phrase ‘‘for 

industrial, commercial, heating, or 

cooling purposes (other than the firstever firing of fuel in a boiler following 

construction of the boiler,’’ as provided 

in paragraph (2) of the definition of 

startup. EGUs trigger the end of startup 

whenever they use either electricity or 

steam for any useful purpose either on 

or offsite. 

54. Table 4 to subpart UUUUU of Part 

63 is revised to clarify that existing as 

well as new EGUs using PM CPMS 

share the same procedures for 


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developing operating limits (i.e., those 

that are based on the higher of a 

parameter scaled from all values 

obtained during an individual emissions 

test to 75 percent of the emissions limit 

or the average parameter value obtained 

from all runs of an individual emission 

test as the operating limit provided that 

the result of the individual emissions 

test met the emissions limit 

requirements). 

55. Table 5 to subpart UUUUU of Part 

63 is revised to state that when using 

Method 5, you are to report the average 

of the final 2 filter weighings, and to 

clarify that when using Method 29, you 

are to report the metals matrix spike and 

recovery levels. These provisions are 

needed for the required electronic 

reporting. 

56. Table 6 to subpart UUUUU of Part 

63 is revised to clarify that existing, as 

well as new, EGUs using PM CPMS 

share the same procedures for 

developing operating limits (i.e., those 

that are based on the higher of a 

parameter scaled from all values 

obtained during an individual emissions 

test to 75 percent of the emissions limit 

or the average parameter value obtained 

from all runs of an individual emission 

test as the operating limit provided that 

the result of the individual emissions 

test met the emissions limit). 

57. Table 8 to subpart UUUUU of Part 

63 is revised to clarify that compliance 

reports are to include information 

required by § 63.10031(c)(5) and (6). 

58. Table 9 to subpart UUUUU of Part 

63 is revised to correct an inadvertent 

omission of 30-day notification 

requirements of § 63.9. 

59. Paragraphs 4.1.1.3 and 5.1.2.3 and 

Tables A–1 and A–2 to Appendix A to 

subpart UUUUU of Part 63 are revised 

to adjust Hg CEMS language regarding 

converters. Research has shown that all 

Hg CEMS need weekly single-level 

system integrity checks. 

60. Paragraph 7.1.2.5 to Appendix A 

to subpart UUUUU of Part 63 is added 

to require that owners or operators flag 

EGUs that are part of emission averaging 

groups. 

61. Paragraph 3.2.1.2.1 of Appendix A 

to subpart UUUUU of Part 63 is revised 

to specifically indicate that Hg gas 

generators and cylinders are allowed. 

62. Paragraphs 4.1.1.1, Table A–1, 

Table A–2, 5.1.2.1, and 4.1.1.3 of 

Appendix A to subpart UUUUU of Part 

63 are revised to exclude use of 

oxidized Hg gas standards for daily 

calibration of Hg CEMS. 

63. Paragraph 5.1.2.3 of Appendix A 

to subpart UUUUU of Part 63 is revised 

to make the weekly single level system 

integrity check mandatory. 

64. Paragraphs 4.1.1.5.2, Table A–1, 

Table A–2, and 4.1.1.5 of Appendix A 

to subpart UUUUU of Part 63 are 

revised to provide an alternative relative 

accuracy test audit (RATA) procedure 

for EGUs with low emissions that is 

related specifically to the emission 

standard. 

65. Paragraph 5.2.1 of Appendix A to 

subpart UUUUU of Part 63 is revised to 

correct the number of days for sorbent 

trap use from 14 to 15. 

66. Paragraph 6.2.2.3 of Appendix A 

to subpart UUUUU of Part 63 is revised 

to clarify that the 90-day alternative Hg 

standard may be used and that electrical 

output is gross output. 

67. Paragraph 7.1.2.6 of Appendix A 

to subpart UUUUU of Part 63 is added 

to clarify that EGU owners or operators 

are to keep records of their EGUs that 

constitute emissions averaging groups. 

68. 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 to subpart UUUUU of Part 

63 are revised to clarify that use of 

Performance Specification (PS) 18, a 

proposed technology-neutral PS for HCl 

CEMS which will soon be promulgated, 

will be allowed. Consistent with our 

statements in the final rule, we expect 

that PS 18 will likely be promulgated in 

advance of the rule’s compliance date. 

An EGU owner or operator who wishes 

to use proposed PS 18, along with 

quality assurance (QA) procedure 6, 

prior to their promulgation dates is 

welcome to submit an alternative 

monitoring request in accordance with 

the requirements of § 63.8(f) for use of 

proposed PS 18 and QA Procedure 6 to 

us. 

69. Paragraph 5.4 of Appendix B to 

subpart UUUUU of Part 63 is added as 

part of the renumbering due to the 

addition of PS 18. 

70. Paragraph 8 of Appendix B to 

subpart UUUUU of Part 63 is revised to 

accommodate use of PS 18. 

71. Paragraphs 10.1.8, 10.1.8.1, 

10.1.8.1.1, and 10.1.8.1.2 of Appendix B 

to Subpart UUUUU of Part 63 are 

revised as part of the renumbering due 

to the addition of PS 18. 

72. Paragraph 10.1.8.1.3 of Appendix 

B to Subpart UUUUU of Part 63 is 

revised to clarify that records of relative 

accuracy audits (RAAs) are also 

required. 

73. Paragraphs 10.1.8.2, 10.1.8.1.2.1, 

and 10.1.8.1.2.2 of Appendix B to 

Subpart UUUUU of Part 63 are revised 

to clarify the quarterly gas audit 

recordkeeping requirements for PS 15 

and the quarterly data accuracy 

assessments for PS 18 (which are 

reserved). 

74. Paragraph 11.4 of Appendix B to 

Subpart UUUUU of Part 63 is revised to 

replace the incorrect abbreviation ‘‘i.e.’’ 

with ‘‘e.g.’’ 

75. Paragraph 11.4.2 of Appendix B to 

Subpart UUUUU of Part 63 is revised to 

specify the requirements of the daily 

beam intensity checks for EGUs using 

PS 18. 

76. Paragraphs 11.4.2.1, 11.4.2.2, 

11.4.2.3, 11.4.2.4, 11.4.2.5, 11.4.2.6, 

11.4.2.7, 11.4.2.8, 11.4.2.9, 11.4.2.10, 

11.4.2.11, 11.4.2.12, and 11.4.2.13 of 

Appendix B to Subpart UUUUU of Part 

63 are revised to hold the requirements 

of the daily beam intensity checks for 

PS 18 (which are reserved). 

77. Paragraph 11.4.3 of Appendix B to 

Subpart UUUUU of Part 63 is revised to 

reflect the reporting requirements for PS 

15. 

78. Paragraphs 11.4.3.1, 11.4.3.2, 

11.4.3.3, 11.4.3.4, 11.4.3.5, 11.4.3.6, 

11.4.3.7, 11.4.3.8, 11.4.3.9, 11.4.3.10, 

11.4.3.11, 11.4.3.12, and 11.4.3.13 of 

Appendix B to Subpart UUUUU of Part 

63 are revised to include PS 15 

reporting requirements. 

79. Paragraph 11.4.4 of Appendix B to 

Subpart UUUUU of Part 63 is revised to 

reserve the reporting requirements for 

quarterly parameter verification checks 

for PS 18. 

80. Paragraphs 11.4.4.1, 11.4.5, 

11.4.5.1, 11.4.6, 11.4.6.1 of Appendix B 

to Subpart UUUUU of Part 63 are added 

to reserve the reporting requirements for 

quarterly gas audit information and for 

quarterly dynamic spiking for PS 18. 

81. Paragraph 11.4.7 of Appendix B to 

Subpart UUUUU of Part 63 is added to 

include reporting requirements for 

RAAs. 

82. Paragraphs 11.4.7.1, 11.4.7.2, 

11.4.7.3, 11.4.7.4, 11.4.7.5, 11.4.7.6, 

11.4.7.7, 11.4.7.8, 11.4.7.9, 11.4.7.10, 

11.4.7.11, 11.4.7.12, and 11.4.7.13 of 

Appendix B to Subpart UUUUU of Part 

63 are added as part of the renumbering 

due to the addition of PS 18. 

83. Paragraph 11.5.3.4 of Appendix B 

to Subpart UUUUU of Part 63 is revised 

to include reporting requirements for 

beam intensity checks for PS 18. 

II. Affirmative Defense for Violation of 

Emission Standards During 

Malfunction 

In several prior CAA section 112 and 

CAA section 129 rules, including this 

rule, the EPA included an affirmative 

defense to civil penalties for violations 

caused by malfunctions in an effort to 

create a system that incorporates some 

flexibility, recognizing that there is a 

tension, inherent in many types of air 

regulation, to ensure adequate 

compliance while simultaneously 

recognizing that despite the most 

diligent of efforts, emission standards 

may be violated under circumstances 


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entirely beyond the control of the 

source. Although the EPA recognized 

that its case-by-case enforcement 

discretion provides sufficient flexibility 

in these circumstances, it included the 

affirmative defense to provide a more 

formalized approach and more 

regulatory clarity. See Weyerhaeuser Co. 

v. Costle, 590 F.2d 1011, 1057–58 (D.C. 

Cir. 1978) (holding that an informal 

case-by-case enforcement discretion 

approach is adequate); but see Marathon 

Oil Co. v. EPA, 564 F.2d 1253, 1272–73 

(9th Cir. 1977) (requiring a more 

formalized approach to consideration of 

‘‘upsets beyond the control of the permit 

holder.’’). Under the EPA’s regulatory 

affirmative defense provisions, if a 

source could demonstrate in a judicial 

or administrative proceeding that it had 

met the requirements of the affirmative 

defense in the regulation, civil penalties 

would not be assessed. Recently, 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 regulations. NRDC v. 

EPA, 749 F.3d 1055 (D.C. Cir., 2014) 

(vacating affirmative defense provisions 

in CAA section 112 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, 749 F.3d at 

1063 (‘‘[U]nder this statute, deciding 

whether penalties are ‘appropriate’ . . . 

is a job for the courts, not EPA.’’). 

In light of NRDC, the EPA is 

proposing to remove the regulatory 

affirmative defense provision in the 

current rule. As explained above, if a 

source is unable to comply with 

emissions standards as a result of a 

malfunction, the EPA may use its caseby-case enforcement discretion to 

provide flexibility, as appropriate. 

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, at 1064 (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. 

III. 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 

subject to review by the Office of 

Management and Budget (OMB). 

B. Paperwork Reduction Act (PRA) 

This action does not impose any new 

information collection burden. This 

action clarifies but does not change the 

information collection requirements 

previously finalized and, as a result, 

does not impose any additional burden 

on industry. The OMB has previously 

approved the information collection 

requirements contained in the existing 

regulations (see 77 FR 9303, February 

16, 2012) under the provisions of the 

PRA, 44 U.S.C. 3501 et seq. and has 

assigned OMB control number 2060– 

0567. The OMB control numbers for the 

EPA’s regulations are listed in 40 CFR 

part 9. 

C. Regulatory Flexibility Act (RFA) 

I certify that this action will not have 

a significant economic impact on a 

substantial number of small entities. 

The EPA has determined that none of 

the small entities will experience a 

significant impact because the action 

imposes no additional regulatory 

requirements on owners or operators of 

affected sources. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This action does not contain an 

unfunded mandate as described in 2 

U.S.C. 1531–1538, and does not 

significantly or uniquely affect small 

governments. 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. This action does not 

significantly or uniquely affect the 

communities of tribal governments. 

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 rulemaking does not involve 

technical standards. 

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. The corrections do not 

involve special consideration of 

environmental justice-related issues as 

required by Executive Order 12898, and 

an evaluation was not necessary for this 

action. 

The EPA’s compliance with the above 

statutes and Executive Orders for the 

underlying rule is discussed in the 

February 16, 2012, Federal Register 

document containing ‘‘National 

Emission Standards for Hazardous Air 

Pollutants from Coal- and Oil-fired 

Electric Utility Steam Generating Units 

and Standards of Performance for 

Fossil-Fuel-Fired Electric Utility, 

Industrial-Commercial-Institutional, and 

Small Industrial-CommercialVerDate Sep<11>2014 19:45 Feb 13, 2015 Jkt 235001 PO 00000 Frm 00009 Fmt 4701 Sfmt 4702 E:\FR\FM\17FEP3.SGM 17FEP3

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8450 Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 

Institutional Steam Generating Units.’’ 

(77 FR 9303). 

List of Subjects 

40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Incorporation by 

reference, Intergovernmental relations, 

Reporting and recordkeeping 

requirements. 

40 CFR Part 63 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Hazardous 

substances, Incorporation by reference, 

Intergovernmental relations, Reporting 

and recordkeeping requirements. 

Dated: December 19, 2014. 

Gina McCarthy, 

Administrator. 

For the reasons discussed in the 

preamble, the EPA proposes to correct 

and amend 40 CFR parts 60 and 63 to 

read 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 

■ 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 40 CFR part 63, subpart YYYY 

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 40 CFR part 

63, subpart DDDDD, 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: 

■ a. Revising paragraph (c)(1)(i); 

■ b. Revising paragraph (c)(2)(iii); and 

■ c. Adding paragraph (m). 

The revisions and additions read as 

follows: 

§ 63.10000 What are my general 

requirements for complying with this 

subpart? 

* * * * * 

(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: 

(A) 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 

exhaust configuration that allows the 

EGU 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) Notwithstanding paragraph 

(c)(1)(i)(A) of this section, you may 

pursue the LEE option provided: 

(1) Your control device bypass stack 

is routed through the EGU main stack so 

that emissions are measured during the 

bypass event; or 

(2) 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 

practicable 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 


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whether your EGU maintains LEE 

status. 

* * * * * 

(2) * * * 

(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. 

* * * * * 

(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. 

§ 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 and (a)(2)(i); 

■ b. Revising paragraph (b)(1); 

■ c. Adding paragraph (b)(6); 

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

■ f. Revising paragraph (f); 

■ g. Revising paragraph (h) introductory 

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

■ h. 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 an 

electrical 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 electrical load 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. 

(1) * * * 

(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 may 

occur on or before the first averaging 

period (30- or, for certain coal-fired 

existing EGUs that use emissions 

averaging for Hg, 90-boiler operating 

days) after the date that compliance 

with this subpart is required but must 

occur such that the averaging period is 

completed on or before the date that 

compliance must be demonstrated. 

(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. 

* * * * * 

(b) * * * 

(1) For a performance test of an 

existing EGU based on stack test data, 

the test was conducted between 180 and 

365 calendar days prior to the date that 

compliance must be demonstrated as 

specified in § 63.9984. 

* * * * * 

(6) If the performance test data that 

are collected prior to the date that 

compliance must be demonstrated 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 must occur 

on or before 180 days after April 16, 

2015. For an existing EGU with a neural 

network, a tune-up must occur on or 

before 180 days after April 16, 2016. If 

a tune-up occurs prior to April 16, 2015, 

you must keep records showing that the 

operating conditions remain the same 

and 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 


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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-boiler operating day test period. 

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. 

* * * * * 

■ 9. Section 63.10006 is amended by 

revising paragraph (f) 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 must 

separate performance tests conducted 

every quarter; 

(ii) At least 370 calendar days must 

separate performance tests conducted 

every year; and 

(iii) At least 1,050 calendar days must 

separate performance tests conducted 

every 3 years. 

(2) Although you are not required to 

operate your EGU solely in order to 

conduct a performance test, you must 

conduct a performance test in the 4th 

quarter of a calendar year if your EGU 

has skipped performance tests in the 3 

quarters of the calendar year. 

(3) If your EGU misses a performance 

test deadline due to being inoperative 

and if you have at least 168 boiler 

operating hours 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 63.10009 is amended by: 

■ a. Revising paragraphs (a)(2) 

introductory text and (a)(2)(i); 

■ b. Revising paragraphs (b)(1) through 

(3); 

■ c. Revising paragraphs (f) introductory 

text and paragraph (f)(2); 

■ d. Revising paragraphs (g)(1) and (2); 

and 

■ e. Revising paragraph (j)(1)(ii). 

The revisions 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 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 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 has operated 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 for hour i 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, 

n = hours in an averaging period (e.g., 720 

for a 30-group boiler operating day 

averaging period or 2160 for a 90-group 

boiler operating day averaging period), 

qj = hours in an averaging period for EGU j 

(e.g., 720 for a 30-group boiler operating 

day averaging period or 2160 for a 90- 

group boiler operating day averaging 

period), 

Terk = Emissions rate (lb/MMBTU or lb/

MWh) from the most recent test of EGU 

k, 

Rmtk = Maximum rated heat input, MMBtu/ 

h, or maximum rated gross output, 

MWh/h, for EGU k, 

rk = hours in an averaging period for EGU k 

(e.g., 720 for a 30-group boiler operating 

day averaging period or 2160 for a 90- 

group boiler operating day averaging 

period), and 

m = number of EGUs in emissions averaging 

group that rely on emissions testing. 


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Where: 

Variables with the similar names share the 

descriptions for Equation 1a, 

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 input or electrical 

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 input or electrical 

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 to calculate the 30 day 

rolling average emissions daily. 

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, 

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 

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, 

Smi = steam generation in units of pounds 

from unit i that uses CEMS or a Hg 


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8454 Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 

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. 

* * * * * 

(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 

possible 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. 

Should the Administrator require 

approval, you must submit your 

proposed emissions averaging plan and 

supporting data at least 120 days before 

the date on which you plan to being 

using emissions averaging. 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 

this section as an alternative to using 

Equation 1a 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) * * * 

(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; 

* * * * * 

■ 11. Section 63.10010 is amended by: 

■ a. Revising paragraph (a)(4); 

■ b. Revising paragraph (f)(3); 

■ c. Revising paragraphs (h)(6)(i) and 

(ii); 

■ d. Revising paragraphs (i)(5)(i)(A) and 

(B); 

■ e. Revising paragraph (j)(1)(i) and 

(j)(4)(i)(A) and (B); and 

■ f. Revising paragraph (l). 

The revisions 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 preceding 30 boiler 

operating days. 

* * * * * 

(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 conducted 

during monitoring system malfunctions. 

You must report any such periods in 

your annual deviation report; 

(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 conducted 

during monitoring system malfunctions. 

You must report any such periods in 

your annual deviation report; 

(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 conducted 

during monitoring system malfunctions. 

You must report any such periods in 

your annual deviation report; 

(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. 

* * * * * 

(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. 

■ 12. 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, consisting 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 certified CEMS, 

expressed in units of the standard, may 

occur on or before the first averaging 

period after the date that compliance 

with the subpart is required but must 

occur such that the averaging period is 

completed on or before the date that 

compliance must be demonstrated. 

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 emission for initial 

compliance, the initial performance test, 

consisting of a 30-boiler operating day 

average emission rate obtained with 

certified CEMS, expressed in units of 

the standard, may occur on or before the 

first averaging period after the date that 

compliance with the subpart is required 

but must occur such that the averaging 

period is completed on or before the 

date that compliance must be 

demonstrated. 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 electrical load 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), the 

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) The request need not address the 

items contained in § 63.6(g)(2). 

(iii) The request shall provide 

evidence of a documented 

manufacturer-identified safety issue. 

(iv) The 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, the request shall 

contain documentation that: 

(A) The EGU is using clean fuels to 

the maximum extent practicable, taking 

into account considerations such as not 

compromising boiler or control device 

integrity, to bring the EGU and PM 

control device up to the temperature 

necessary to alleviate or prevent the 

identified safety issues prior to the 

combustion of primary fuel in the EGU; 

(B) The EGU has explicitly followed 

the manufacturer’s procedures to 

alleviate or prevent the identified safety 

issue; and 

(C) Identifies with specificity the 

details of the manufacturer’s statement 

of concern. 

(vi) The request shall specify the other 

work practice standards the EGU owner 

or operator 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, 


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recordkeeping, and reporting 

requirements. 

■ 13. 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 differential pressure across the 

scrubber of the liquid during each hour 

of startup. 

■ 14. Section 63.10021 is amended by 

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

introductory text, and (e)(9)(i) and (ii) 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 

delay the 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. 

* * * * * 

(9) * * * 

(i) If the first tune-up is performed 

prior to April 16, 2015, report the date 

of the tune-up in hard copy (as specified 

in § 63.10030) and electronically (as 

specified in § 63.10031). Report the date 

of each subsequent tune-up 

electronically (as specified in 

§ 63.10031). 

(ii) If the first tune-up is performed on 

or after April 16, 2015, report the date 

of the tune-up and all subsequent tuneups electronically, in accordance with 

§ 63.10031. 

* * * * * 

■ 15. Section 63.10023 is amended by 

removing and reserving paragraph (b)(1) 

and revising (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: 

* * * * * 

■ 16. 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); 

■ 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 

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 

§ 63.10006(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 § 63.10006(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. 


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(A) You may switch between mass per 

heat input and mass per gross output 

levels, provided: 

(1) You submit a Notification of 

Compliance Status that identifies for 

each EGU or EGU emissions averaging 

group involved in proposed switch both 

the current and proposed emission 

limit; 

(2) Your submission arrives to the 

Administrator at least 30 calendar days 

prior to the date that the switch is 

proposed to occur; 

(3) Your submission demonstrates 

through performance stack test results 

conducted 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 electric output limits; 

(4) You revise and submit all other 

applicable plans, e.g., monitoring and 

emissions averaging, with your 

submission; and 

(5) You maintain records of all 

information regarding your choice of 

emission limits. 

(B) You may begin to use the revised 

emission limits the semi-annual 

reporting period after receipt of written 

acknowledgement from the 

Administrator of the switch. 

(C) From submission until the semiannual reporting period after receipt of 

written acknowledgement from the 

Administrator of the switch, you must 

demonstrate compliance with both the 

mass per heat input and mass per 

electric 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 

(M) 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. 

(f) You must submit the notifications 

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

apply to you by the dates specified. 

■ 17. Section 63.10031 is amended by: 

■ a. Revising paragraphs (c)(4) and (5); 

■ b. Adding paragraph (c)(6); and 

■ c. Revising paragraph (f)(5). 

The revisions and addition read as 

follows: 

§ 63.10031 What reports must I submit and 

when? 

* * * * * 

(c) * * * 

(4) Include the date of the most recent 

tune-up for each EGU. For the first tuneup, include the date of the burner 

inspection if it was delayed. 

(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 

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) Emergency bypass reports from 

EGUs with LEE status. 

* * * * * 

(f) * * * 

(5) All reports required by this 

subpart not subject to the requirements 

in paragraphs (f)(1) through (4) of this 

section must be sent to the 

Administrator at the appropriate 

address listed in § 63.13. If acceptable to 

both the Administrator and the owner or 

operator of an EGU, these reports may 

be submitted on electronic media. The 

Administrator retains the right to 

require submittal of reports subject to 

paragraphs (f)(1) through (4) of this 

section in paper format. 

* * * * * 

■ 18. 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 

clean fuel capacity for each EGU; 

(ii) The determination of the 

maximum 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). 

* * * * * 

■ 19. Section 63.10042 is amended by: 

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


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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, a 

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. 

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 combusting more than 25 

MW 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 onsite 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. 

* * * * * 

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. 

* * * * * 

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 April 

16, 2015. 

* * * * * 

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 

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. 

* * * * * 

■ 20. 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 Subpart UUUUU of 

Part 63—Performance Testing 

Requirements . . . 

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 


tkelley on DSK3SPTVN1PROD with PROPOSALS3
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 8459 

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 Subpart UUUUU of 

Part 63—Performance Testing 

Requirements . . . 

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 

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 

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.


tkelley on DSK3SPTVN1PROD with PROPOSALS3
8460 Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 

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 Subpart UUUUU of 

Part 63—Performance Testing 

Requirements . . . 

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, 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 oilfired 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 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—non-continental (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. 

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.


tkelley on DSK3SPTVN1PROD with PROPOSALS3
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 8461 

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 Subpart UUUUU of 

Part 63—Performance Testing 

Requirements . . . 

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. 

1Gross output. 

2 Incorporated by reference, see § 63.14. 

3You 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. 

■ 21. Revise Table 2 to subpart UUUUU 

of part 63 to read as follows: 


tkelley on DSK3SPTVN1PROD with PROPOSALS3
8462 Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 

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 Subpart UUUUU of 

Part 63—Performance Testing 

Requirements . . . 

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, 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 ................... 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 10 

days maximum per Method 30B 

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 10 

days maximum 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.

b. Hydrogen chloride (HCl) ........... 2.0E–3 lb/MMBtu or 2.0E–2 lb/

MWh.

For Method 26A, collect a minimum of 0.75 dscm per run; for 

Method 26, collect a minimum 

of 120 liters per run. 

For ASTM D6348–03 3 or Method 

320, sample for a minimum of 1 

hour. 

OR 


tkelley on DSK3SPTVN1PROD with PROPOSALS3
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 8463 

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 Subpart UUUUU of 

Part 63—Performance Testing 

Requirements . . . 

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 10 

days maximum 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 10 

days maximum per Method 30B 

run or Hg CEMS or sorbent trap 

monitoring system only. 

4. Liquid oil-fired unit—continental 

(excluding limited-use liquid 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.

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. 


tkelley on DSK3SPTVN1PROD with PROPOSALS3
8464 Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 

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 Subpart UUUUU of 

Part 63—Performance Testing 

Requirements . . . 

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.

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.


tkelley on DSK3SPTVN1PROD with PROPOSALS3
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 8465 

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 Subpart UUUUU of 

Part 63—Performance Testing 

Requirements . . . 

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 10 

days maximum 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. 

■ 22. 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.

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 practicable, 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 within 4 hours of start of electricity generation. 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. 

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. 


tkelley on DSK3SPTVN1PROD with PROPOSALS3
8466 Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 

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 . . . 

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. 

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). Any fraction of an hour in which startup occurs 

constitutes a full hour of startup. 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. 

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 practicable. 

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. 

■ 23. 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). 

■ 24. Revise Table 5 to subpart UUUUU 

of part 63 to read as follows: 


tkelley on DSK3SPTVN1PROD with PROPOSALS3

EP17FE15.006</GPH>tkelley on DSK3SPTVN1PROD with PROPOSALS3

Table 5 to Subpart UUUUU of Part 63 - Performance Testing Requirements 

As stated in§ 63.10007, you must comply with the following requirements 

testing for existing, new or reconstructed affected sources

To conduct a 

performance 

test for ... 

following 

pollutant 

1. !!Emissions 

Filterable Testing Particulate 

matter (PM) 

You must perform 

the following 

activities, as 

applicable to 

2 

your input- or 

output-based 

emission limit a. Select IIMethod 1 at Appendix A-1 to Part 

sampling ports chapter. 

location and the 

number of 

traverse points. 

b. Determine 

velocity and volumetric flowrate of the 

stack gas. 

c. Determine 

oxygen and 

carbon dioxide 

concentrations 

of the stack 

gas. 

!

Method 2, 2A, 2C, 2F, 2G or 2H a

A-2 to Part 60 of this chapter. 

Method 3A or 3B at Appendix A-2 

this chapter, or ANSI/ASME PTC 1

EP17FE15.007</GPH>tkelley on DSK3SPTVN1PROD with PROPOSALS3

d. Measure the Method 4 at Appendix A-3 to Part 

moisture content chapter. 

of the stack 

gas. 

e. Measure the Method 5 at Appendix A-3 to Part 

filterable PM chapter. When using Method 5, use 

concentration. the final 2 filter weightings. I !For positive pressure fabric filt

at Appendix A-3 to Part 60 of th

filterable PM emissions. 

I I !Note that the Method 5 front hal

shall be 160° ± 14°C (320° ± 25°

f. Convert Method 19 F-factor methodology a

emissions Part 60 of this chapter, or calcconcentration to emissions rate and electrical ou

lb/MMBtu or 63.10007(e)). lb/MWh emissions 

rates. 

loR lloR I 

PM CEMS a. Install, Performance Specification 11 at A

certify, Part 60 of this chapter and Proc

operate, and Appendix F to Part 60 of this ch

maintain the PM 

CEMS. 

b. Install, Part 75 of this chapter and §§ 6

certify, (c), and (d). 

operate, and 

maintain the 

diluent gas, 

EP17FE15.008</GPH>tkelley on DSK3SPTVN1PROD with PROPOSALS3

2. Total or 

individual 

non-Hg HAP 

metals 

Emissions 

Testing 

flow rate, 

and/or moisture 

monitoring 

systems. 

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 

of this chapter, or calculate us

emissions rate and electrical ou

63.10007 (e)) . 

a. Select IIMethod 1 at Appendix A-1 to Part 

sampling ports chapter. 

location and the 

number of 

traverse points. 

b. Determine 

velocity and volumetric flowrate of the 

stack gas. 

c. Determine 

oxygen and 

carbon dioxide 

concentrations 

of the stack 

gas. 

Method 2, 2A, 2C, 2F, 2G or 2H a

IA-2 to Part 60 of this chapter. 

Method 3A or 3B at Appendix A-2 

this chapter, or ANSI/ASME PTC 1

EP17FE15.009</GPH>tkelley on DSK3SPTVN1PROD with PROPOSALS3

d. Measure the Method 4 at Appendix A-3 to Part 

moisture content 

of the stack 

gas. 

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. 

f. Convert 

emissions concentrations 

(individual HAP 

metals, total 

filterable HAP 

metals, and 

total HAP 

metals) to 

lb/MMBtu or lb/MWh emissions 

Method 29 at Appendix A-8 to Par

chapter. For liquid oil-fired un

included in HAP metals and you m

Method 30B at Appendix A-8 to Pa

chapteri for Method 29, you must 

half and back half results separ

Method 29, report metals matrix 

recovery levels. 

Method 19 F-factor methodology a

Part 60 of this chapter, or calc

emissions rate and electrical ou

63.10007(e)). 

EP17FE15.010</GPH>tkelley on DSK3SPTVN1PROD with PROPOSALS3

3. Hydrogen 

chloride 

(HCl) and 

hydrogen 

fluoride 

(HF) 

Emissions 

Testing 

rates. 

a. Select IIMethod 1 at Appendix A-1 to Part 

sampling ports chapter. 

location and the 

number of 

traverse points. 

b. Determine 

velocity and volumetric flowrate of the 

stack gas. 

c. Determine 

oxygen and 

carbon dioxide 

concentrations 

of the stack 

gas. 

d. Measure the 

Method 2, 2A, 2C, 2F, 2G or 2H a

A-2 to Part 60 of this chapter. 

Method 3A or 3B at Appendix A-2 

this chapter, or ANSI/ASME PTC 1

Method 4 at Appendix A-3 to Part 

moisture content 

of the stack 

gas. 

e. Measure the 

HCl and HF 

emissions concentrations. 

Method 26 or Method 26A at Appen

60 of this chapter or Method 320 

Part 63 of this chapter or ASTM 

the following conditions using A

(A) The test plan preparation an

in the Annexes to ASTM D6348-03, 

through A8 are mandatory; (B) Fo

Annex A5 (Analyte Spiking Techniq

EP17FE15.011</GPH>tkelley on DSK3SPTVN1PROD with PROPOSALS3

II OR 

HCl and/or HF CEMS 

f. Convert 

emissions concentration to 

lb/MMBtu or lb/MWh emissions 

rates. 

II OR 

(%) R must be determined for each 

(see Equation A5.5); (C) For the 

test data to be acceptable for a 

%R must be 70 % R 130%; and 

for each compound must be reporte

report and all field measurement

the calculated %R value for that the following equation: 

R d R 1t (Measured Concentratio

epo1 te esu1, = 

%R 

and (2)spiking levels nominally 

two times the level corresponding 

applicable emission limit. 

Method 26A must be used if there 

water droplets in the exhaust str

Method 19 F-factor methodology a

Part 60 of this chapter, or calc

emissions rate and electrical ou

63.10007 (e)) . 

a. Install, IIAppendix B of this subpart. 

certify, 

operate, and 

maintain the HCl 

or HF CEMS. 

b. Install, 

certify, 

Part 75 of this chapter and§§ 6

(c) , and (d) . 

EP17FE15.012</GPH>tkelley on DSK3SPTVN1PROD with PROPOSALS3

4. Mercury 

(Hg) 

Emissions 

Testing 

operate, and 

maintain the 

diluent gas, 

flow rate, 

and/or moisture 

monitoring 

systems. 

c. Convert 

hourly emissions 

concentrations 

to 30 boiler 

operating day 

rolling average 

lb/MMBtu or lb/MWh emissions 

rates. 

a. Select 

sampling ports 

location and the 

number of 

traverse points. 

b. Determine 

velocity and 

volumetric flowrate of the 

stack gas. 

c. Determine 

oxygen and 

carbon dioxide 

Method 19 

F-factor methodology at Appendix 

of this chapter, or calculate us

emissions rate and electrical ou

63.10007 (e)) . 

Method 1 at Appendix A-1 to Part 

chapter or Method 30B at Appendix 

30B point selection. 

Method 2, 2A, 2C, 2F, 2G or 2H a

A-2 to Part 60 of this chapter. 

Method 3A or 3B at Appendix A-1 

this chapter, or ANSI/ASME PTC 1

EP17FE15.013</GPH>tkelley on DSK3SPTVN1PROD with PROPOSALS3

concentrations 

of the stack 

gas. 

d. Measure the Method 4 at Appendix A-3 to Part 

moisture content chapter. 

of the stack 

gas. 

e. Measure the Method 30B at Appendix A-8 to Pa

Hg emission chapter, ASTM D6784 3 I or Method 2

concentration. 8 to Part 60 of this chapter; fo

must report the front half and b

separately. 

f. Convert Method 19 F-factor methodology a

emissions Part 60 of this chapter, or calcconcentration to emissions rate and electrical ou

lb/TBtu or 63.10007 (e)) . 

lb/GWh emission 

rates. 

loR II oR I 

Hg CEMS a. Install, Sections 3.2.1 and 5.1 of Append

certify, subpart. 

operate, and 

maintain the 

CEMS. 

b. Install, Part 75 of this chapter and §§ 6

certify, (c) , and (d) . 

operate, and 

maintain the 

diluent gas, 

EP17FE15.014</GPH>tkelley on DSK3SPTVN1PROD with PROPOSALS3

flow rate, 

and/or moisture 

monitoring 

systems. 

c. Convert Section 6 of Appendix A to this 

hourly emissions 

concentrations 

to 30 boiler 

operating day 

rolling average 

lb/TBtu or 

lb/GWh emissions 

rates. 

lOR OR 

Sorbent a. Install, Sections 3.2.2 and 5.2 of Append

trap certify, subpart. 

monitoring operate, and 

system maintain the 

sorbent trap 

monitoring 

system. 

b. Install, Part 75 of this chapter and §§ 6

operate, and (C) 1 and (d) . 

maintain the 

diluent gas, 

flow rate, 

and/or moisture 

monitoring 

systems. 

EP17FE15.015</GPH>tkelley on DSK3SPTVN1PROD with PROPOSALS3

OR 

c. Convert emissions concentrations 

to 30 boiler 

operating day 

rolling average 

lb/TBtu or 

lb/GWh emissions 

rates. 

OR 

LEE Select 

sampling ports 

location and the 

number of 

traverse points. 

b. Determine 

velocity and volumetric flowrate of the 

stack gas. 

c. Determine 

oxygen and 

carbon dioxide 

concentrations 

of the stack 

gas. 

d. Measure the 

moisture content 

of the stack 

gas. 

Section 6 of Appendix A to this Single point located at the 10% 

of the duct at a port location p

!Appendix A-1 to Part 60 of this 

30B at Appendix A-8 for Method 30

selection. 

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

or A-2 to Part 60 of this chapte

monitoring system certified per A

this subpart. 

Method 3A or 3B at Appendix A-1 

this chapter, or ANSI/ASME PTC 1

diluent gas monitoring systems c

according to Part 75 of this cha

Method 4 at Appendix A-3 to Part 

chapter, or moisture monitoring according to Part 75 of this cha

EP17FE15.016</GPH>tkelley on DSK3SPTVN1PROD with PROPOSALS3

5. Sulfur 

dioxide 

(802) 

802 CEMS 

e. Measure the 

Hg emission 

concentration. 

f. Convert 

emissions concentrations 

from the LEE 

test to lb/TBtu 

or lb/GWh 

emissions rates. 

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. 

a. Install, 

certify, 

operate, and 

maintain the 

CEMS. 

b. Install, 

operate, and 

maintain the 

Method 30B at Appendix A-8 to Pa

chapter; perform a 30 operating d

maximum of 10 operating days per 

pair of sorbent traps) or sorben

system or Hg CEMS certified per A

this subpart. 

Method 19 F-factor methodology a

Part 60 of this chapter, or calc

emissions rate and electrical ou

63.10007 (e)) . 

Potential maximum annual heat inp

potential maximum electricity ge

Part 75 of this chapter and§§ 6

(f) . 

Part 75 of this chapter and §§ 6

(c), and (d) . 
■ 25. Revise Table 6 to subpart UUUUU 

of part 63 to read as follows: 


EP17FE15.017</GPH>tkelley on DSK3SPTVN1PROD with PROPOSALS3

diluent gas, 

flow rate, 

and/or moisture 

monitoring 

systems. 

c. Convert 

hourly emissions 

concentrations 

to 30 boiler 

operating day 

rolling average 

lb/MMBtu or lb/MWh emissions 

rates. 

Method 19 F-factor methodology a

Part 60 of this chapter, or calc

emissions rate and electrical ou

63.10007(e)). 

1 Regarding emissions data collected during periods of startup or shutdown

63.10020(b) and (c) and 63.10021(h). 

2 See Tables 1 and 2 to this subpart for required sample volumes and/or sam

times. 

3 Incorporated by reference, see§ 63.14. 
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 8479 

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 nonmercury 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. 

■ 26. 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 for reports:] 

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 (6); 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). 

■ 27. 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. 


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8480 Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules 

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 

§ 63.6(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 for the 60-day notification prior to 

conducting a performance test in § 63.9(d); 

instead use a 30-day notification period per 

§ 63.10030(d). 

§ 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. 

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

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

■ 28. Appendix A to subpart UUUUU of 

part 63 is amended by: 

■ a. Revising paragraph 3.2.1.2.1; 

■ b. Revising paragraphs 4.1.1.1, 4.1.1.3, 

4.1.1.5, and 4.1.1.5.2; 

■ c. Revising Tables A–1 and A–2; 

■ d. Revising paragraphs 5.1.2.1, 5.1.2.3, 

and 5.2.1; and 

■ e. Adding paragraph 6.2.2.3 and 

7.1.2.6. 

The revisions and additions to read as 

follows: 

Appendix A to Subpart UUUUU of Part 

63—Hg Monitoring Provisions 

* * * * * 

3. Mercury Emissions Measurement Methods 

* * * * * 


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3.2.1.2.1 NIST Traceability. Only NISTcertified 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 high-level or a 

mid-level calibration gas standard (as defined 

in sections 3.1.8, 3.1.10, and 3.1.11 of this 

appendix). Use a NIST-traceable elemental 

Hg gas standard (as defined in section 3.1.4 

of this appendix) for the test. 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. 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 non-consecutive calendar 

days. On each day of the test, inject the zerolevel 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. 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. 

* * * * * 

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’’ (mg/ 

dscm), and 

Cb = Hg concentration of Hg sample ‘‘b’’ (mg/ 

dscm). 

* * * * * 

4.1.1.5.2 Calculation of RATA Results. 

Calculate the relative accuracy (RA) of the 

monitoring system, on a mg/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. 

* * * * * 

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 ........... |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 ............................. |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. 

RATA ............................................. 20.0% RA ..................................... ≤10% RA when concentration 

equivalent of applicable emissions limit is used in place of 

RMavg in Equation 2–6 of PS2 

(see Section 4.1.1.5.2 of this 

appendix).

RMavg <50% of applicable emissions limit. 


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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 . . . 

Cycle time test 2 ............................. 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. The cycle time test is not required for Hg CEMS that use integrated batch sampling; however, those monitors must be capable of recording at least one Hg concentration reading every 15 minutes. 3 Use elemental Hg standards. 

4 Use oxidized Hg standards. 

* * * * * 5. Ongoing Quality Assurance (QA) and Data 

Validation 

* * * * * 

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 ...................... Daily .............................................. • Use either a mid- or high-level 

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.

|Rn ¥ 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 ≥50% of 

the emissions limit 

or 

≤10.0% RA when Cavg <50% of 

the emissions limit and the concentration equivalent of the applicable emission limit is used in 

the denominator of Equation 2– 

6 of PS2 (see Section 4.1.1.5.1 

of this appendix). 

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. 

* * * * * 

5.1.2.1 Calibration error tests of the Hg 

CEMS are required daily, except during unit 

outages. Use a NIST-traceable elemental Hg 

gas standard for these calibrations. Both a 

zero-level gas and either a mid-level or highlevel 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). 

* * * * * 

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 output-based 

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: 


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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. 

* * * * * 

■ 29. Appendix B to subpart UUUUU of 

part 63 is amended by: 

■ a. Revising paragraph 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. On-Going Quality Assurance 

Requirements; 

■ e. Revising paragraphs 5.1, 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; 

■ g. Revising section 8. introductory 

text; 

■ h. Revising paragraphs 10.1.8, 

10.1.8.1, 10.1.8.1.1, and 10.1.8.1.2, 

adding paragraph 10.1.8.1.2.1, and 

adding and reserving paragraph 

10.1.8.1.2.2; 

■ i. Revising paragraph 10.1.8.1.3; 

■ j. Revising paragraphs 11.4 and 11.4.2 

and removing and reserving paragraphs 

11.4.2.1 through 11.4.2.13; 

■ k. Revising paragraphs 11.4.3 and 

11.4.3.1 through 11.4.3.13; 

■ l. Revising paragraph 11.4.4 and 

adding and reserving paragraph 

11.4.4.1; 

■ m. Adding paragraph 11.4.5 and 

adding and reserving paragraph 

11.4.5.1; 

■ n. Adding paragraph 11.4.6 and 

adding and reserving paragraph 

11.4.6.1; 

■ o. Adding paragraphs 11.4.7, 11.4.7.1 

through 11.4.7.13; 

■ p. Revising paragraph 11.4.8 and 

■ q. Revising paragraph 11.5.3.4. 

■ 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 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 and 

§ 63.10010(a) or Performance Specification 

18 (PS 18) of appendix B to part 60 of this 

chapter for HCl CEMS and § 63.10010(a). 

* * * * * 

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 Performance 

Specification 15 (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 Performance 

Specification 18 (PS 18) of appendix B to part 

60 of this chapter, then your HCl and/or HF 

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 5.3.2 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 of Procedure 6 of 

40 CFR part 60, appendix F shall apply. 

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-ofcontrol, 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 out-of-control when a 

required QA test is not performed on 

schedule or within an allotted grace period. 

To end an out-of-control period, the QA test 

that was either failed or not done on time 

must be performed and passed. Out-ofcontrol 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 

quality-assurance 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 flow rate, diluent gas, and 

moisture 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 or 

HF 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/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 required under in section 

5.3 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/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, and for the 

required QA tests when non-redundant 

backup monitoring systems or temporary 

like-kind replacement analyzers are brought 

into service, 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 gas audit or data accuracy 

assessment shall be the same as for a linearity 

check (i.e., 168 unit or stack operating hours). 

* * * * * 


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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 the other monitoring 

systems described in paragraph 5.3 of this 

appendix are specified in section 1 of 

appendix B to part 75 of this chapter. 

* * * * * 

10. Recordkeeping Requirements 

* * * * * 

10.1.8 Certification and Quality 

Assurance Test Records. For the HCl and/or 

HF CEMS used to provide data under this 

subpart at each affected unit (or group of 

units monitored at a common stack), record 

the following information for all required 

certification, recertification, diagnostic, and 

quality-assurance tests: 

10.1.8.1 HCl and HF CEMS. 

10.1.8.1.1 For all required daily 

calibrations and checks (including 

calibration transfer standard tests) of the HCl 

or HF CEMS, record the test dates and times, 

reference values and their certification 

information, action levels for integrated path 

HCl CEMS, HCl or HF monitor responses, 

and calculated calibration error values; 

10.1.8.1.2 For quarterly gas audits of HCl 

or HF CEMS certified under PS 15 of 

appendix B to part 60 of this chapter follow 

paragraph 10.1.8.1.2.1 of this appendix and 

for quarterly data accuracy assessments 

under PS 18 of appendix B to part 60 of this 

chapter follow paragraph 10.1.8.1.2.2 of this 

appendix. 

10.1.8.1.2.1 Record the date and time of 

each spiked and unspiked sample, the audit 

gas reference values and uncertainties. Keep 

records of all calculations and data analyses 

required under sections 9.1 and 12.1 of P S 

15 of appendix B to part 60 of this chapter, 

and the results of those calculations and 

analyses. 

10.1.8.1.2.2 [Reserved] 

10.1.8.1.3 For each RATA or RAA of a 

HCl or HF CEMS, record the date and time 

of each test run, the reference method(s) 

used, and the reference method and HCl or 

HF CEMS values. Keep records of the data 

analyses and calculations used to determine 

the relative accuracy. 

* * * * * 

11. Reporting Requirements 

* * * * * 

11.4 Certification, Recertification, and 

Quality-Assurance Test Reporting 

Requirements. Except for daily QA tests (e.g., 

calibrations and flow monitor interference 

checks), which are included in each 

electronic quarterly emissions report, use the 

ECMPS Client Tool to submit the results of 

all required certification, recertification, 

quality-assurance, and diagnostic tests of the 

monitoring systems required under this 

appendix electronically, either prior to or 

concurrent with the relevant quarterly 

electronic emissions report. 

* * * * * 

11.4.2 For daily beam intensity checks for 

integrated path HCl CEMS as specified by PS 

18 of appendix B to part 60 of this chapter, 

report: 

11.4.2.1 through 11.4.2.13 [Reserved] 

11.4.3 For each quarterly gas audit of an 

HCl or HF CEMS under Performance 

Specification 15, report: 

11.4.3.1 Facility ID information; 

11.4.3.2 Monitoring system ID number; 

11.4.3.3 Type of test (e.g., quarterly gas 

audit); 

11.4.3.4 Reason for test; 

11.4.3.5 Certified audit (spike) gas 

concentration value (ppm); 

11.4.3.6 Measured value of audit (spike) 

gas, including date and time of injection; 

11.4.3.7 Calculated dilution ratio for 

audit (spike) gas; 

11.4.3.8 Date and time of each spiked flue 

gas sample; 

11.4.3.9 Date and time of each unspiked 

flue gas sample; 

11.4.3.10 The measured values for each 

spiked gas and unspiked flue gas sample 

(ppm); 

11.4.3.11 The mean values of the spiked 

and unspiked sample concentrations and the 

expected value of the spiked concentration as 

specified in section 12.1 of PS 15 of appendix 

B to part 60 of this chapter (ppm); 

11.4.3.12 Bias at the spike level as 

calculated using equation 3 in section 12.1 of 

PS 15 of appendix B to part 60 of this 

chapter; and 

11.4.3.13 The correction factor (CF), 

calculated using equation 6 in section 12.1 of 

PS 15 of appendix B to part 60 of this 

chapter. 

11.4.4 For each quarterly parameter 

verification check for an integrated path HCl 

CEMS under PS 18 of appendix B to part 60 

of this chapter, report: 

11.4.4.1 [Reserved] 

11.4.5 For each quarterly gas audit under 

P S 18 of appendix B to part 60 of this 

chapter, report: 

11.4.5.1 [Reserved] 

11.4.6 For each quarterly dynamic 

spiking audit as allowed by P S 18 of 

appendix B to part 60 of this chapter, report: 

11.4.6.1 [Reserved] 

11.4.7 For each RATA or RAA of an HCl 

or HF CEMS, report: 

11.4.7.1 Facility ID information; 

11.4.7.2 Monitoring system ID number; 

11.4.7.3 Type of test (i.e., initial or annual 

RATA or RAA); 

11.4.7.4 Reason for test; 

11.4.7.5 The reference method used; 

11.4.7.6 Starting and ending date and 

time for each test run; 

11.4.7.7 Units of measure; 

11.4.7.8 The measured reference method 

and CEMS values for each test run, on a 

consistent moisture basis, in appropriate 

units of measure; 

11.4.7.9 Flags to indicate which test runs 

were used in the calculations; 

11.4.7.10 Arithmetic mean of the CEMS 

values, of the reference method values, and 

of their differences; 

11.4.7.11 Standard deviation, as specified 

in Equation 2–4 of PS 2 or PS 18, as 

applicable in appendix B to part 60 of this 

chapter; 

11.4.7.12 Confidence coefficient, as 

specified in Equation 2–5 of PS 2 or PS 18, 

as applicable in appendix B to part 60 of this 

chapter; and 

11.4.7.13 Relative accuracy calculated 

using Equation 2–6 of PS 2 or PS 18, as 

applicable in appendix B to part 60 of this 

chapter or, if applicable, according to the 

alternative procedure for low emitters 

described in paragraph 3.1.2.2 of this 

appendix. If applicable use a flag to indicate 

that the alternative RA specification for low 

emitters has been applied. 

* * * * * 

11.4.8 Reporting Requirements for 

Diluent Gas, Flow Rate, and Moisture 

Monitoring Systems. For the certification, 

recertification, diagnostic, and QA tests of 

stack gas flow rate, moisture, and diluent gas 

monitoring systems that are certified and 

quality-assured according to part 75 of this 

chapter, report the information in section 

10.1.8.2 of this appendix. 

* * * * * 

11.5.3.4 The results of all daily 

calibrations (including calibration transfer 

standard tests and beam intensity checks of 

integrated path CEMS) of the HCl or HF 

monitor as described in paragraph 10.1.8.1.1 

of this appendix; and 

* * * * * 

[FR Doc. 2015–01699 Filed 2–13–15; 8:45 am] 

BILLING CODE 6560–50–P 


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