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EO12866_MATS_Reconsideration_2060-AR62_Final_20130319

6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

EPA-HQ-OAR-2009-0234; EPA-HQ-OAR-2011-0044 [FRL-9789-5]

RIN 2060-AR62

Reconsideration of Certain New Source and Startup/Shutdown 

Issues: National Emission Standards for Hazardous Air Pollutants 

from Coal- and Oil-fired Electric Utility Steam Generating Units 

and Standards of Performance for Fossil-Fuel-Fired Electric 

Utility, Industrial-Commercial-Institutional, and Small 

Industrial-Commercial-Institutional Steam Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule; notice of final action on reconsideration.

SUMMARY: The EPA is taking final action on its reconsideration 

of certain issues in the final rules 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, IndustrialCommercial-Institutional, and Small Industrial-CommercialInstitutional Steam Generating Units.” The National Emission 

Standards for Hazardous Air Pollutants (NESHAP) rule issued 

pursuant to Clean Air Act (CAA) section 112 is referred to as 

the Mercury and Air Toxics Standards (MATS) NESHAP, and the New 
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Source Performance Standards rule issued pursuant to CAA section 

111 is referred to as the Utility NSPS. The Administrator 

received petitions for reconsideration of certain aspects of the 

MATS NESHAP and the Utility NSPS.

On November 30, 2012, the EPA granted reconsideration of, 

proposed, and requested comment on a limited set of issues. We 

also proposed certain technical corrections to both the MATS

NESHAP and the Utility NSPS. The EPA is now taking final action 

on the revised new source numerical standards in the MATS NESHAP 

and the definitional and monitoring provisions in the Utility 

NSPS that were addressed in the proposed reconsideration rule.

As part of this action, the EPA is also making certain technical 

corrections to both the MATS NESHAP and the Utility NSPS. The 

EPA is not taking final action on requirements applicable during 

periods of startup and shutdown in the MATS NESHAP or on startup

and shutdown provisions related to the PM standard in the 

Utility NSPS.

DATES: The effective date of the rule is [INSERT THE DATE OF 

PUBLICATION IN THE FEDERAL REGISTER].

Docket. The EPA established two dockets for this action: Docket 

ID EPA-HQ-OAR-2011-0044 (NSPS action) and Docket ID EPA-HQ-OAR2009-0234 (MATS NESHAP action). All documents in the dockets are 
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listed in the http://www.regulations.gov index. Although listed 

in the index, some information is not publicly available (e.g., 

confidential business information (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.

FOR FURTHER INFORMATION CONTACT: For the MATS NESHAP action: Mr. 

William Maxwell, Energy Strategies Group, Sector Policies and 

Programs Division, (D243-01), Office of Air Quality Planning and 

Standards, U.S. Environmental Protection Agency, Research 

Triangle Park, North Carolina 27711; Telephone number: (919) 

541-5430; Fax number (919) 541-5450; Email address: 

maxwell.bill@epa.gov. For the NSPS action: Mr. Christian

Fellner, Energy Strategies Group, Sector Policies and Programs 

Division, (D243-01), Office of Air Quality Planning and 
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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:

Outline. The information presented in this preamble is organized 

as follows:

I. General Information

A. Does this action apply to me?

B. How do I obtain a copy of this document?

C. Judicial Review

II. Background

III. Summary of Today’s Action

IV. Summary of Final Action and Changes Since Proposal – MATS 

NESHAP New Source Issues

V. Summary of Final Action and Changes Since Proposal – Utility 

NSPS

VI. Technical Corrections and Clarifications

VII. Impacts of this Final Rule

A. Summary of Emissions Impacts, Costs and Benefits

B. What are the air impacts?

C. What are the energy impacts?

D. What are the compliance costs?

E. What are the economic and employment impacts?

F. What are the benefits of the final standards?

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review

B. Paperwork Reduction Act

C. Regulatory Flexibility Act

D. Unfunded Mandates Reform Act

E. Executive Order 13132: Federalism

F. Executive Order 13175: Consultation and Coordination

With Indian Tribal Governments

G. Executive Order 13045: Protection of Children from 
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Environmental Health Risks and Safety Risks

H. Executive Order 13211: Actions that Significantly

Affect Energy Supply, Distribution, or Use

I. National Technology Transfer and Advancement Act

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-income 

Populations

K. Congressional Review Act

I. General Information

A. Does this action apply to me?

Categories and entities potentially affected by today’s 

action include:

Category NAICS 

code1

Examples of potentially 

regulated entities

Industry 221112 Fossil fuel-fired electric 

utility steam generating units.

Federal government 2211222 Fossil fuel-fired electric 

utility steam generating units 

owned by the Federal 

government.

State/local/Tribal 

government

2211222

921150

Fossil fuel-fired electric 

utility steam generating units 

owned by municipalities.

Fossil fuel-fired electric 

utility steam generating units 

in Indian country.

1 North American Industry Classification System.

2 Federal, State, or local government-owned and operated 

establishments are classified according to the activity in which 

they are engaged.

This table is not intended to be exhaustive but rather to 

provide a guide for readers regarding entities likely to be 

affected by this action. To determine whether your facility, 

company, business, organization, etc. would be regulated by this 
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action, you should examine the applicability criteria in 40 CFR 

60.40, 60.40Da, or 60.40c or in 40 CFR 63.9982. If you have any 

questions regarding the applicability of this action to a 

particular entity, consult either the air permitting authority 

for the entity or your EPA regional representative as listed in 

40 CFR 60.4 or 40 CFR 63.13 (General Provisions).

B. How do I obtain a copy of this document?

In addition to being available in the docket, electronic 

copies of these final rules will be available on the Worldwide 

Web (WWW) through the Technology Transfer Network (TTN). 

Following signature, a copy of the action will be posted on the 

TTN’s policy and guidance page for newly proposed or promulgated 

rules at the following address: http://www.epa.gov/ttn/oarpg/. 

The TTN provides information and technology exchange in various 

areas of air pollution control.

C. Judicial Review

Under the CAA section 307(b)(1), judicial review of this 

final rule is available only by filing a petition for review in 

the U.S. Court of Appeals for the District of Columbia Circuit 

by [INSERT DATE 60 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL 

REGISTER]. Under CAA section 307(d)(7)(B), only an objection to 

this final rule that was raised with reasonable specificity 
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during the period for public comment can be raised during 

judicial review. Note, under CAA section 307(b)(2), the 

requirements established by this final rule may not be 

challenged separately in any civil or criminal proceedings 

brought by the EPA to enforce these requirements.

II. Background

The final MATS NESHAP and the Utility NSPS rules were 

published in the Federal Register at 77 FR 9304 on February 16, 

2012. Following promulgation of the final rules, the 

Administrator received petitions for reconsideration of numerous 

provisions of both the MATS NESHAP and the Utility NSPS pursuant 

to CAA section 307(d)(7)(B). Copies of the MATS NESHAP petitions 

are provided in rulemaking docket EPA-HQ-OAR-2009-0234. Copies 

of the Utility NSPS petitions are provided in rulemaking docket 

EPA-HQ-OAR-2011-0044. On November 30, 2012, the proposal 

granting reconsideration of certain issues in the MATS NESHAP

and Utility NSPS was published in the Federal Register at 77 FR 

71323.

III. Summary of Today’s Action

This final action amends certain provisions of the final 

rule issued by the EPA on February 16, 2012. Through an August 

2, 2012, notice (77 FR 45967), the EPA delayed the effective 
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date of the February 2012 rule for new sources only. That stay 

was limited to 90 days and has since expired. The February 2012 

final rule is and remains in effect for all sources.

The November 30, 2012, proposed reconsideration rule

proposed: (1) certain revised new source numerical standards in

the MATS NESHAP, (2) requirements applicable during periods of 

startup and shutdown in the MATS NESHAP, (3) startup and 

shutdown provisions related to the particulate matter (PM)

standard in the Utility NSPS, and (4) definitional and 

monitoring provisions in the Utility NSPS. We also proposed

certain technical corrections to both the MATS NESHAP and the 

Utility NSPS. We are taking final action today on the revised 

numerical new source MATS NESHAP limits, the definitional and 

monitoring issues in the Utility NSPS, and all of the technical 

corrections not related to startup/shutdown issues.

This summary of the final rule reflects the changes to 40 

CFR Part 63, subpart UUUUU, and 40 CFR Part 60, subpart Da (77 

FR 9304; February 16, 2012) made in this regard. 

As noted above, in the proposed reconsideration rule, the 

EPA took comment on the requirements in the MATS NESHAP 

applicable during startup and shutdown, including the 

definitions of startup and shutdown. The EPA also took comment 
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on the startup and shutdown provisions relating to the PM 

standard in the Utility NSPS. The EPA received considerable 

comments regarding these startup and shutdown provisions, 

including data and information relevant to the proposed work 

practice standard that applies in such periods. The EPA is not 

taking final action on the startup and shutdown issues at this 

time as it needs additional time to consider and evaluate the 

comments and data provided.1 The Agency is currently reviewing 

all of the comments received on the startup and shutdown issues 

and intends to act promptly to address these issues. We note 

that no existing sources will have to comply with the existing 

source MATS standards before April 16, 2015. Further, no new 

sources are currently under construction and it takes years to 

complete construction. 77 FR 71330, fn. 7. As such, there will 

be sufficient time for the Agency to review the comments 

submitted concerning the proposed startup and shutdown 

provisions and take appropriate action well in advance of any 

new source being subject to the standards.

As described below, on the basis of information provided 

since the reconsideration proposal, today’s action revises

 

1 The EPA is also still reviewing the other issues raised in the 

petitions for reconsideration and is not taking any action at 

this time with respect to those issues.
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certain new source numerical limits in the MATS NESHAP. 

Specifically, the EPA is finalizing revised hydrogen chloride 

(HCl), filterable PM (fPM),2 sulfur dioxide (SO2), lead (Pb), and 

selenium emission limits for all new coal-fired EGUs; the 

mercury (Hg) emission limit for the “unit designed for coal >

8,300 Btu/lb subcategory;” fPM and SO2 emission limits for new 

solid oil-derived fuel-fired EGUs; fPM emission limits for new 

continental liquid oil-fired EGUs; and most of the emission 

limits for new integrated gasification combined cycle (IGCC)

units.

The fPM, HCl, and Hg limits that we are finalizing in this 

action are provided in table 1; the alternate limits that we are 

finalizing are provided in table 2.3

TABLE 1. REVISED EMISSION LIMITATIONS FOR NEW EGUS

Subcategory

Filterable 

particulate 

matter, lb/MWh

Hydrogen 

chloride, 

lb/MWh

Mercury, 

lb/GWh

New - Unit not 

designed for 

low rank 

virgin coal

9.0E-2 1.0E-2

a 3.0E-3

New - Unit 

designed for 

low rank 

9.0E-2 1.0E-2

a NR

 

2 As the final MATS rule established a filterable PM (fPM) limit, 

every mention of a PM limit means filterable PM.

3 The final rule included certain alternative limits (see 77 FR 

9367 – 9369).
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virgin coal

New – IGCC 7.0E-2

b

9.0E-2

c 2.0E-3 3.0E-3

New – Solid 

oil-derived 3.0E-2 NR NR

New – Liquid 

oil -

continental

3.0E-1 NR NR

Note: lb/MWh = pounds pollutant per megawatt-hour electric 

output (gross)

lb/GWh = pounds pollutant per gigawatt-hour electric output 

(gross)

NR = limit not opened for reconsideration (77 FR 9304; February 

16, 2012)

a Beyond-the-floor value

b Duct burners on syngas; based on permit levels in comments 

received

c Duct burners on natural gas; based on permit levels in comments 

received

TABLE 2. REVISED ALTERNATE EMISSION LIMITATIONS FOR NEW EGUS

Subcategory

/

Pollutant

Coal-fired 

EGUs

IGCCa Solid oilderived

SO2 1.0 lb/MWh 4.0E-1 lb/MWhb 1.0 lb/MWh

Total nonmercury 

metals

NR 4.0E-1 lb/GWh NR

Antimony, Sb NR 2.0E-2 lb/GWh NR

Arsenic, As NR 2.0E-2 lb/GWh NR

Beryllium, Be NR 1.0E-3 lb/GWh NR

Cadmium, Cd NR 2.0E-3 lb/GWh NR

Chromium, Cr NR 4.0E-2 lb/GWh NR

Cobalt, Co NR 4.0E-3 lb/GWh NR

Lead, Pb 2.0E-2 lb/GWh 9.0E-3 lb/GWh NR

Mercury, Hg NA NA NR

Manganese, Mn NR 2.0E-2 lb/GWh NR

Nickel, Ni NR 7.0E-2 lb/GWh NR

Selenium, Se 5.0E-2 lb/GWh 3.0E-1 lb/GWh NR

NA = not applicable

NR = limit not opened for reconsideration (77 FR 9304; February 

16, 2012)
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a Based on best-performing similar source

b Based on DOE information

In addition, in the MATS NESHAP the EPA is removing

quarterly stack testing as an option to demonstrate compliance 

with the new source fPM emission limits; revising the way in 

which an owner or operator of a new EGU who chooses to use PM 

continuous parameter monitoring systems (CPMS) establishes an 

operating limit; requiring inspections and retesting within 45 

days of an exceedance of the operating limit for those new EGU 

owners or operators who choose to use PM CPMS as a compliance 

option; and retaining the presumption of violation of the 

emissions limit if more than 4 emissions tests are required in a 

12-month period.

These final changes incorporate information about the 

variability of the best performing EGUs and more accurately 

reflect the capabilities of emission control equipment for new 

EGUs. The final changes should also address commenters’ concerns 

that vendors of EGU emission controls had been unwilling to 

provide guarantees regarding the ability to meet all of the 

standards for new EGUs as originally finalized in February 2012.

We expect that source owners and operators will install and 

operate the same or similar control technologies to meet the 
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revised standards in this reconsideration action as they would 

have chosen to comply with the standards in the February 2012 

final rule. Consistent with CAA section 112(a)(4), we are 

maintaining the new source trigger date for the MATS NESHAP rule

as May 3, 2011. See 77 FR 71330, fn. 7. New sources must comply 

with the revised MATS emission standards described in section IV 

below by [INSERT DATE OF PUBLICATION OF RULE IN FEDERAL 

REGISTER], or startup, whichever is later.

In the February 2012 final Utility NSPS rule, the EPA 

adopted a definition of natural gas that excludes coal-derived 

synthetic natural gas consistent with the definition in MATS. In 

the Utility NSPS reconsideration proposal, we re-proposed and 

requested comment on that definition. Based on review of the 

comments received in response to the reconsideration proposal, 

the EPA has concluded that the definition of natural gas in the 

final Utility NSPS is appropriate and, therefore, is not making 

any changes to that definition. We are also finalizing as 

proposed one conforming amendment and two amendments related to 

EGUs burning desulfurized coal-derived synthetic natural gas. 

First, we amended the definition of coal to make it clear that 

coal-derived synthetic natural gas is considered to be coal. In 

addition, in recognition of the fact that emissions from the 
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burning of desulfurized coal-derived synthetic natural gas are 

very similar to those from the burning of natural gas, we 

amended the opacity and SO2 monitoring provisions so that 

facilities burning desulfurized coal-derived synthetic natural 

gas will have opacity and SO2 monitoring requirements similar to 

those of facilities burning natural gas. Further, we are 

finalizing certain revisions to the definition of IGCC in the 

Utility NSPS. We are also finalizing as proposed the revised 

procedures for calculating PM emission rates intended to make 

the Utility NSPS procedures consistent with those in the MATS 

NESHAP. We did not receive any adverse comments regarding this 

proposed change. Finally, we are finalizing as proposed the 

technical corrections to the PM standards for facilities that 

commenced construction before March 1, 2005, and for facilities 

that commence modification after May 3, 2011.

The impacts of today’s revisions on the costs and the 

benefits of the final rule are minor. As noted above, we expect 

that source owners and operators will install and operate the 

same or similar control technologies to meet the revised 

standards in this action as they would have chosen to comply 

with the standards in the February 2012 final rule.

IV. Summary of Final Action and Changes Since Proposal – MATS 
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NESHAP New Source Issues

After consideration of the public comments received, the 

EPA has made certain changes in this final action from the

reconsideration proposal. We address the most significant 

comments in this preamble. However for a complete summary of the 

comments received on the issues we are finalizing today and our 

responses thereto, please refer to the memorandum “National 

Emission Standards For Hazardous Air Pollutants From Coal- And 

Oil-Fired Electric Utility Steam Generating Units –

Reconsideration; Summary Of Public Comments And Responses”

(March 2013) in rulemaking docket EPA-HQ-OAR-2009-0234.

In this action, we are finalizing certain new source 

emission limits for the MATS NESHAP, as discussed below. 

1. Changes to Certain New Source MATS NESHAP Limits

Commenters noted that in two instances, Pb emissions from 

coal-fired EGUs and the fPM emissions from continental liquid 

oil-fired EGUs, the EPA had proposed new source emission limits 

that were less stringent than those in the final MATS NESHAP for

the respective existing sources. This approach was inconsistent 

with that taken in the final MATS NESHAP.

4 Although CAA section 

 

4 See “National Emission Standards for Hazardous Air Pollutants 

(NESHAP) Maximum Achievable Control Technology (MACT) Floor 
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112(d)(3) allows existing source MACT floor limits to be less 

stringent than new source limits, the EPA interprets this 

provision as precluding new source limits from being less 

stringent than existing source limits. See CAA section 

112(d)(3). Thus, for Pb emissions from coal-fired EGUs and fPM 

emissions from continental liquid oil-fired EGUs, the EPA is 

finalizing new source limits that are equivalent to the final 

existing-source limits.

Next, commenters noted that when evaluating SO2 emissions

data from coal-fired EGUs, the EPA had not selected the lowest 

emitting source upon which to base the emission limit and that 

its rationale for excluding certain data was unlawful and 

arbitrary. Although the EPA disagrees with commenters on several 

of the excluded data sets (i.e., some of the data sets suggested 

by commenters comprised only a single 3-run average for each EGU

with no individual run data, making assessment of variability 

impossible), it agrees that it inadvertently omitted the data 

from Stanton Unit 10 in the proposal analyses. Stanton Unit 10 

does have a lower “lowest” 3-run data average than does the EGU 

selected for the new source analysis (Sandow Unit 5A) in the 

 

Analysis for Coal- and Oil-fired Electric Utility Steam 

Generating Units for Final Rule,” Docket ID EPA-HQ-OAR-2009-

0234-20132, p. 13.
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proposed reconsideration rule.

In this final action, the EPA used the Stanton data to 

calculate the MACT floor using the same statistical analyses 

used in the proposed rule (i.e., 99 percent upper predictive 

limit (UPL)), and the resulting MACT floor emission limit is 1.3 

pounds per megawatt-hour (lb/MWh). Because this limit is less 

stringent than the new source performance standard (NSPS) 

finalized in the Utility NSPS (77 FR 9451; February 16, 2012), 

the EPA is finalizing a beyond-the-floor (BTF) MACT standard of 

1.0 lb/MWh, which is the same level required by the CAA section 

111 NSPS for these same sources.5 See 40 CFR 60.43Da(l)(1)(i).

Cost is a required consideration in establishing CAA section 111 

rules and in going BTF in establishing CAA section 112 rules. We 

evaluated cost in assessing whether to go BTF for this standard 

and concluded that it was appropriate to go BTF to a level of 

1.0 lb/MWh. Moreover, the NSPS limit (also 1.0 lb/MWh) is in 

place and coal-fired EGUs are required to comply with that 

 

5 The CAA section 111 standard is based on the performance of 

EGUs with the best performing SO2 controls, a reasonable 

incremental cost effectiveness of less than $1,000 per ton of SO2

controlled, and controls that result in minimal secondary 

environmental and energy impacts.
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limit. As such, there is no additional cost to these sources.

6

Furthermore, we have not identified any non-air quality health 

or environmental impacts or energy requirements associated with

the final standard set at this level. In addition, at 

reconsideration proposal, we evaluated going BTF more stringent 

than the NSPS level and found it not to be cost effective.7 For 

these reasons, we are finalizing 1.0 lb/MWh as the new source 

MATS NESHAP limit, which is the same limit required for SO2

emissions for new coal-fired EGUs under the Utility NSPS.

In the proposed reconsideration rule, we indicated that 

detection level issues may arise from using a sorbent trap when 

short sampling periods (e.g., 30 minutes) are used. As such, the 

EPA solicited comment on its establishment of a Representative 

Detection Level (RDL) associated with Hg sorbent traps. The EPA 

also solicited comment on whether the UPL calculated floor 

should be compared against the 3XRDL value for Hg to account for 

the shorter sampling periods (the 3XRDL approach). The EPA 

 

6 The final Utility NSPS limit was not challenged and coal-fired 

EGUs constructed after May 3, 2011, must meet that limit.

7 See Docket ID EPA-HQ-OAR-2009-0234-20221 and National Emission 

Standards for Hazardous Air Pollutants (NESHAP) Beyond the 

Maximum Achievable Control Technology (MACT) Floor (‘Beyond-theFloor’) Analysis for Revised Emission Standards for New Source 

Coal-and Oil-fired Electric Utility Steam Generating Units also 

in the rulemaking docket.
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received several comments, ranging from strong support for the 

Hg RDL and the proposed emission limit because, at that level, 

the commenters asserted that vendors would be able to provide 

commercial guarantees, to concerns about the specific inputs to 

the 3XRDL calculation and the application of the 3xRDL approach. 

See section 2.2.1 of the response to comments document (RTC) for 

a more complete discussion and response to these comments. 

In the proposed reconsideration rule, the EPA recognized 

that 30 minutes of sample collection is the shortest reasonable 

amount of time available for collecting and changing sorbent 

tubes to provide the quick, reliable feedback that will allow 

sources to react to changing Hg emissions levels and assure 

compliance with the final Hg limit. Some commenters pointed out 

that the EPA’s memorandum entitled “Determination of

Representative Detection Level (RDL) and 3 X RDL Values for 

Mercury Measured Using Sorbent Trap Technologies,”

8 contains a 

30-minute sample collection time in the 3XRDL calculation, but 

the text of the memorandum references a 20-minute sample 

 

8 The EPA developed the memorandum to determine appropriate RDL 

and 3XRDL values for sorbent trap monitoring systems, as well as 

calculate an emissions limit, in order to determine the 

shortest, reasonable sample collection period for those systems. 

See EPA Docket ID EPA-HQ-OAR-2009-0234-20222.
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collection time. The EPA has revised the text of the memorandum 

to reflect its original intent, which was to focus on a sample 

collection period of 30 minutes (not 20 minutes). The revised 

memorandum focuses on the 30-minute sample collection period. 

Given that it takes 5 minutes for sorbent trap insertion and 

removal, it would take a total of 40 minutes to secure the 

requisite sample collection (30 minutes for sample collection, 5 

minutes to remove the sorbent trap, and 5 minutes to re-insert 

the trap). We are finalizing the Hg limit using the 3XRDL 

approach assuming a 30-minute sampling time.

2. Filterable PM Testing, Monitoring, and Compliance 

Certification for New EGUs in the MATS NESHAP Rule

Several monitoring options for the fPM standard for new 

sources were provided in the MATS NESHAP final rule, including 

quarterly stack testing, PM CEMS, and PM CPMS with annual 

testing. 

The EPA sought comment on whether to retain the quarterly 

stack testing compliance option for new EGUs, given that 

continuous, direct measurement of fPM or a correlated parameter 

is available, is preferable for determining compliance on a 

continuous basis, and is likely to be used by most new EGUs to 

monitor compliance with the proposed new source standards. As 
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mentioned above, this final action does not retain the quarterly 

fPM performance testing option for new EGUs. New EGUs can be 

designed to incorporate PM CEMS or PM CPMS from the outset, 

without being impeded by retrofit location installation 

constraints that could impact existing EGUs. This final action

now requires new sources to use either PM CEMS or PM CPMS as 

options for determining compliance with the new source fPM 

limits.

The EPA requested comment on a number of issues associated 

with PM CPMS. The EPA identified three approaches to establish 

an operating limit based on emissions testing for those EGU 

owners or operators who choose to use PM CPMS as the means of 

demonstrating compliance with the fPM emission limit. The first 

approach, which was proposed and contained in the final MATS 

NESHAP rule, would require an EGU owner or operator to use the 

highest parameter value obtained during any run of an individual 

emissions test as the operating limit. The second approach would 

require an EGU owner or operator to use the average parameter 

value obtained from all runs of an individual emissions test as 

the operating limit, provided that the result of the individual 

emissions test met the emissions limit. The third approach, 

which the EPA is finalizing in this final action, would require 
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an EGU owner or operator to use the higher of the following: (1) 

a parameter scaled from all values obtained during an individual 

emissions test to 75 percent of the emissions limit or (2) the 

average parameter value obtained from all runs of an individual 

emissions test as the operating limit, provided that the result 

of the individual emissions test met the emissions limit. As 

established and reaffirmed in the recent Sewage Sludge 

Incineration, Major Source Industrial Boiler, and Portland 

Cement rules,

9 increased operational flexibility and reduced 

emissions testing are available for those sources which emit at 

or below 75 percent of a standard – whether an emissions or 

operating limit. Reduced emissions testing is available in this 

final rule for those owners or operators whose EGU emissions do 

not exceed this 75 percent threshold. This 75 percent threshold 

allows for compliance flexibility and is simultaneously

protective of the emission standards. The EPA believes well 

 

9 See Standards of Performance for New Stationary Sources and 

Emission Guidelines for Existing Sources: Commercial and 

Industrial Solid Waste Incineration Units, 76 FR 15736 (March 

21, 2011); Subpart DDDDD—National Emission Standards for 

Hazardous Air Pollutants for Major Sources: Industrial, 

Commercial, and Institutional Boilers and Process Heaters, 40 

CFR 63.7515(b); and National Emission Standards for Hazardous 

Air Pollutants for the Portland Cement Manufacturing Industry 

and Standards of Performance for Portland Cement Plants, 78 FR 

10014 (February 12, 2013).
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performing EGUs, i.e., those whose emissions do not exceed 75 

percent of the emissions limit, should not face additional 

scrutiny or testing consequences provided their emissions remain 

equivalent to or below the 75 percent threshold. In this final 

action, the EPA uses the 75 percent threshold so as not to

impose unintended and costly retest requirements for the lowest 

emitting sources and to provide for more cost effective, 

continuous, PM parametric monitoring across the EGU sector. This 

approach was selected from the options considered as it provides

the greatest amount of EGU owner or operator flexibility while

demonstrating continuous compliance for EGUs. With this 

parametric monitoring approach in place, the EPA expects EGUs to 

evaluate control options that provide excellent fPM emissions 

control and provide them greater operational flexibility.

Moreover, after each exceedance of the operating limit, the 

EPA proposed to require emissions testing to verify or re-adjust 

the operating limit, consistent with the approach contained in 

the recently-promulgated Portland cement MACT standard (see 78 

FR 10014). One commenter objected to potential frequent 

emissions testing to reassess the operating limit and then being 

subject to a violation of the emissions limit. The EPA does not 

believe that too-frequent testing will be required. As discussed 
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in section 4.3.5 of the RTC, the EPA believes well-designed 

emissions testing will provide an operating limit corresponding 

with EGU operation, and such testing should yield an operating 

limit that would not be expected to be exceeded during the 

course of EGU operation. Therefore, an operating limit developed 

from well-designed emissions testing should have little, if any, 

need for frequent reassessment via emissions testing more 

frequently than the mandated annual reassessment because the 

source will be able to meet the limit on an ongoing basis.

Finally, the EPA proposed that PM CPMS exceedances leading 

to more than 4 required emissions tests in a 12-month period

(rolling monthly) would be presumed (subject to the possibility 

of rebuttal by the EGU owner or operator) to be a violation of 

the emissions limit, consistent with the approach contained in 

the newly-promulgated Portland cement MACT standard (see 78 FR 

10014). The EPA received a number of comments on this proposed 

provision, including comments supporting and opposing the 

establishment of such a presumption.

The EPA disagrees with those comments opposing the 

presumptive violation, and believes the presumptive violation 

provision in the final rule is a reasonable and appropriate 

approach to ensure compliance with the standard. First, the EPA 
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may permissibly establish such an approach by rule, assuming 

there is a reasonable factual basis to do so. See Hazardous 

Waste Treatment Council v. EPA, 886 F. 2d 355, 367–68 (DC Cir.

1989) (explaining that such presumptions can legitimately 

establish the elements of the EPA’s prima facie case in an 

enforcement action). Second, there is a reasonable basis here 

for the presumption that four exceedances (i.e., increases over 

the parametric operating limit) in a calendar year are a 

violation of the emission standard. The parametric monitoring 

limit is established as a 30-day average of the averaged test 

value in the performance test, or the 75th percentile value if 

that is higher. In either instance, the 30-day averaging feature

provides significant leeway to the EGU owner or operator not to

deviate from the parametric operating level because use of the 

hourly values collected during 30 boiler operating days will

significantly dampen variability in the single measurement 

(average of three test runs) that produced the parametric value. 

See 77 FR 42377/2 and sources there cited. See also 78 FR 10015, 

10019; February, 12, 2013 (Portland Cement MACT) and the RTC for 

today’s action.

The EPA also received comments addressing the re-testing 

requirements following an exceedance. Some commenters expressed 
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concern about the burden of requiring sources to conduct 

performance tests in order to demonstrate compliance and to 

reassess the parameter level. In contrast, other commenters 

supported a requirement to require re-testing but claimed that 

the time period between observing a parameter exceedance and 

retesting is too long. The EPA believes that the re-testing 

requirements are reasonable and appropriate to identify noncompliance without imposing undue burden. For even a single 

exceedance to occur, the 30-day average would have to be higher 

than the operating limit established for the PM CPMS during 

normal EGU operation. If that occurs, then the EGU owner or 

operator is required to conduct an inspection to determine any 

abnormalities and an emissions test to re-establish or generate 

a new operating limit. Given that EGUs and their emissions 

control devices are designed to operate at known, specific 

conditions, deviations from these conditions are not expected 

and are indicative of problems with load, controls, or some 

combination of both. Where these sorts of problems result in an 

exceedance of the source’s operating limit, it is reasonable to 

require re-testing in order to identify and then correct 

problems. More than four such exceedances of the 30-day average 

would mean that the EGU owner or operator was unable to 
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determine or correct the problem, since inspection and recalculation of the operating limit is required after each 

exceedance. This indicates an ongoing problem with maintaining 

process control and/or control device operation, which would be 

the basis for a presumptive violation of the emissions standard.

Moreover, the EPA disagrees that the period between exceedance 

of the operating limit and retesting is too long and could 

result in possible excessive emissions. Specifically, some 

commenters claimed that the final rule should not limit the 

number of exceedances of the PM CPMS limit that require followup performance tests in any 12-month period. These commenters 

alleged that to do so does not ensure continuous compliance 

because the time period between an exceedance and testing could 

be too long, and a source could be exceeding the emission limit 

during that time period. The EPA believes that the re-testing 

requirements reflect a reasonable balance between ensuring 

compliance and limiting unnecessary testing burden on regulated 

sources. An EGU owner or operator is required to visually 

inspect the air pollution control device within 48 hours of the 

exceedance, and corrective action must be taken as soon as 

possible to return the PM CPMS measurement to within the 

established value. A performance test is also required within 45 
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days of the exceedance to determine compliance and verify or reestablish the PM CPMS limit. Thus, the EPA finds it unlikely 

that there will be long periods of noncompliance with the 

underlying fPM standard given the inspection and performance 

testing requirements.

The EPA also received comments stating that an EGU owner or 

operator should not be labeled a “violator” of the fPM standard

as a result of a fourth successful compliance test in a 12-month 

period. First, the EPA notes that the presumption of a violation 

is just that – a presumption – and can be rebutted in any 

particular case. Moreover, in determining whether the 

presumption has been successfully rebutted, a Court may consider 

relevant information such as data or other information showing 

that the EGU’s operating process remained in control during the 

period of operating parameter exceedance, that the ongoing 

operation and maintenance conducted on the EGU ensured its 

emissions control devices remained in proper operating condition 

during the period of operating parameter exceedance, and that 

results of emissions tests conducted while replicating the 

conditions observed during the period of operating parameter 

exceedance remained below the emission limit.

For the reasons explained above, this final action includes
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the presumption of violation of the emissions limit if more than 

4 emissions tests are required in a 12-month period.

V. Summary of Final Action and Changes Since Proposal – Utility 

NSPS

The EPA has made a number of changes from the 

reconsideration proposal in this final action after 

consideration of the public comments received. Most are changes 

to clarify applicability and implementation issues raised by the 

commenters. The public comments received on the matters proposed 

for reconsideration and the responses to them can be viewed in 

the memorandum “Summary of EGU NSPS Public Comments and 

Responses on Amendments Proposed November 30, 2012 (77 FR 

71323)” in rulemaking docket EPA-HQ-OAR-2011-0044.

In the proposed reconsideration rule, the EPA proposed a 

new definition for IGCC which would be consistent with the MATS 

NESHAP definition. However, as an alternative we also 

specifically requested comment on whether to retain a definition 

similar, but not identical, to the IGCC definition in the 

February 2012 final Utility NSPS. We have concluded that the 

alternative approach is most appropriate and are adopting a 

slightly revised definition that is consistent with the Agency’s 

statements on IGCC contained in the RTC in support of the final 
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rule published on February 16, 2012 (77 FR 9304). Commenters 

generally supported amending the final Utility NSPS definition

of IGCC, and this final action amends that definition consistent 

with the statements made in the RTC for the Utility NSPS. The 

Utility NSPS definition deals with the intent of an IGCC 

facility and is, thus, broader than the MATS NESHAP definition. 

The facility would still be subject to the same criteria 

pollutant emission standards even when burning natural gas for 

extended periods of time. The MATS NESHAP applicability is 

determined based on the EGUs utilization of coal and oil and the 

rule may not apply depending on the extent of natural gas usage.

The EPA proposed that the NSPS PM monitoring procedures be 

consistent with the MATS NESHAP requirements and included the 

use of quarterly stack testing, PM CPMS, or PM CEMS. In 

addition, the EPA sought comment on whether to include the 

quarterly stack testing compliance option for new EGUs, given 

that continuous, direct measurement of PM or a correlated 

parameter is available. EGUs complying with an output-based 

emissions standard can be designed to incorporate PM CEMS or PM 

CPMS from the outset, without being impeded by retrofit location 

installation constraints that would impact existing EGUs. This 

final action requires EGUs complying with an output-based 
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standard to use either PM CEMS or PM CPMS as options for 

determining compliance with the PM limits. Therefore, the EPA is 

finalizing the same monitoring procedures for PM for the Utility 

NSPS as for new sources subject to the MATS NESHAP, and is not 

finalizing the quarterly stack testing option.

The EPA proposed that facilities using PM CPMS would be 

able to use either a continuous opacity monitoring system or a 

periodic alternate monitoring approach to monitor opacity. This 

final action does not require facilities using a PM CPMS to 

conduct opacity monitoring. The EPA has concluded that the use 

of a PM CPMS at the level of the emissions standard required in 

subpart Da is sufficient to demonstrate compliance with the 

opacity standard and that additional monitoring is an 

unnecessary burden.

VI. Technical Corrections and Clarifications

On April 19, 2012 (77 FR 23399), the EPA issued a technical 

corrections notice addressing certain corrections to the 

February 16, 2012 (77 FR 9304), MATS NESHAP and Utility NSPS. In 

the November 30, 2012, reconsideration proposal, we proposed

several additional technical corrections. Specific to the NSPS, 

we proposed correcting the PM standard for facilities that 

commenced construction before March 1, 2005, to remove the extra 
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significant digit that was inadvertently added and to correct 

the PM standard for facilities that commence modification after 

May 3, 2011, to be consistent with the original intent as 

expressed in the RTC of the final rule published on February 16, 

2012 (77 FR 9304). We did not receive any negative comments on 

these issues and are finalizing them as proposed. Specific 

details are included in Table 3.

Specific to the MATS NESHAP, the EPA requested comment on 

whether the proposed technical corrections in Table 4 of the 

preamble provide the intended accuracy, clarity, and 

consistency. As mentioned in section 6.3 of the RTC, commenters 

supported the proposed changes on equations 2a and 3a and this

final action contains those changes. As mentioned in section 6.3 

of the RTC, commenters did not support the change from a 30 to 

60 day notification period for performance testing, and that 

change was not made to the rule; however, a change to the 

General Provisions applicability table was made to provide a 

consistent 30-day notification period. Commenters suggested 

changes to certain definitions to make them more consistent with 

the Acid Rain rule provisions, but as described in section 6.4 

of the RTC, these rule changes were not made. These amendments 

are now being finalized to correct inaccuracies and other 
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inadvertent errors in the final rule and to make the rule 

language consistent with provisions addressed through this 

reconsideration.

The final technical changes are described in tables 3 and 4

of this preamble.

TABLE 3. MISCELLANEOUS TECHNICAL CORRECTIONS TO 40 CFR PART 60, 

SUBPART Da

Section of subpart Da Description of correction

40 CFR 60.42Da(a) Correct the erroneous “0.030” to 

the correct “0.03”

40 CFR 60.42Da(e)(1)(ii) Correct the erroneous conversion 

“13 ng/J (0.015 lb/MMBtu)” to 

the correct “6.4 ng/J (0.015 

lb/MMBtu)” by amending the 

regulatory text to specify that 

the requirements in 40 CFR 

60.42Da(c) or (d), which 

includes two additional 

alternative limits, are 

available compliance 

alternatives for modified 

facilities

TABLE 4. MISCELLANEOUS TECHNICAL CORRECTIONS TO 40 CFR PART 63, 

SUBPART UUUUU

Section of subpart UUUUU Description of correction

40 CFR 63.9982(a) Clarify the language to use the 

word “or” instead of “and.”

40 CFR 63.9982(b) and (c) Correct the discrepancy between 

63.9982(b) and (c) and 

63.9985(a)

40 CFR 63.10005(d)(2)(ii) Correct the typographical error 

by replacing the incorrect 
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“corresponding” with the correct 

“corresponds.”

40 CFR 63.10005(i)(4)(ii) 

and (i)(5) and add 

63.10005(i)(6)

Revise to clarify the 

determination and measurement of 

fuel moisture content.

40 CFR 63.10006(c) Correct the omission of solid 

oil-derived fuel- and coal-fired 

EGUs and IGCC EGUs and the 

omission of section 10000(c).

40 CFR 63.10007(c) Correct the omission of section 

63.10023 from the list of 

sections to be followed in 

establishing an operating limit.

40 CFR 63.10009(b)(2) Correct omission of the term 

“boiler operating” and clarify 

the term “Rti” in Equation 2a.

40 CFR 63.10009(b)(3) Correct omission of the term 

“system” and clarify the term 

“Rti” in Equation 3a.

40 CFR 63.10010(j)(1)(i) Correct the typographical error 

to use the correct word “your”

instead of “you.”

40 CFR 63.10030(b), (c), 

and (d)

Clarify the affected-source 

language.

Change the period by which a

Notification of Intent to 

conduct a performance test must 

be submitted to conform to the 

General Provisions.

40 CFR Section 63.10042 Correct the typographical error 

in the intended definition of 

“unit designed for coal ≥ 8,300 

Btu/lb subcategory” by replacing 

the erroneous “>“ with the 

correct “≥.”

Table 5 to Subpart UUUUU 

of Part 63

Correct the typographical error 

in footnote 4 by replacing the 

erroneous “>“ with the correct 

“<.”
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Table 7 to Subpart UUUUU 

of Part 63

Clarify the applicability of the 

alternate 90-day average for Hg 

in item 1.

Revise item 3 in the table to 

clarify use of CMS for liquid 

oil-fired EGUs.

Table 9 to Subpart UUUUU 

of Part 63

Revise to clarify the period for 

notification of conducting a 

performance test from 60 to 30 

days.

Section 4.1 to Appendix A 

to Subpart UUUUU of Part 

63

Correct the typographical error 

by replacing the incorrect 

citation to “§63.10005(g)” with 

the correct “§63.9984(f).”

Section 5.2.2.2 to 

Appendix A to Subpart 

UUUUU of Part 63

Correct the typographical error 

by replacing the incorrect 

citation to “Table A-4” with the 

correct “Table A-2”

Section 3.1.2.1.3 to 

Appendix B to Subpart 

UUUUU of Part 63

Correct the typographical error 

by replacing the erroneous “>“

with the correct “<.”

Section 5.3.4 to Appendix 

B to Subpart UUUUU of Part 

63

Correct the section number from 

the incorrect “5.3.4” to the 

correct “5.3.3.”

VII. Impacts of this Final Rule

A. Summary of Emissions Impacts, Costs and Benefits

Our analysis shows that new EGUs would choose to install 

and operate the same or similar air pollution control 

technologies in order to meet the revised emission limits as 

would have been necessary to meet the previously finalized 

standards. We project that this final action will result in no 
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significant change in costs, emission reductions, or benefits.10

Even if there were changes in costs for these EGUs, such changes 

would likely be small relative to both the overall costs of the 

individual projects and the overall costs and benefits of the 

final rule. Further, we believe that EGUs would put on the same 

controls for this final action that they would have for the 

original final MATS rule, so there should not be any incremental 

costs related to this revision.

B. What are the air impacts?

We believe that electric power companies will install the 

same or similar control technologies to comply with the final

standards in this action as they would have installed to comply 

with the previously finalized MATS standards. Accordingly, we 

believe that this final action will not result in significant 

changes in emissions of any of the regulated pollutants.

C. What are the energy impacts?

This final action is not anticipated to have an effect on 

 

10 See Regulatory Impact Analysis for the Final Mercury and Air 

Toxics Standards [EPA-452/R-11-011] (docket entry EPA-HQ-OAR2009-0234-20131) and Economic Impact Analysis for the Final 

Reconsideration of the Mercury and Air Toxics Standards in 

rulemaking docket EPA-HQ-OAR-2009-0234. As noted earlier, 

because on an individual EGU-by-EGU basis we anticipate very 

similar costs, any changes to the baseline since we finalized 

MATS (e.g., potential impacts of the CSAPR decision) would not 

impact this determination.
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the supply, distribution, or use of energy. As previously

stated, we believe that electric power companies would install 

the same or similar control technologies as they would have 

installed to comply with the previously finalized MATS 

standards.

D. What are the compliance costs?

We believe there will be no significant change in 

compliance costs as a result of this final action because 

electric power companies would install the same or similar 

control technologies as they would have installed to comply with 

the previously finalized MATS standards. Moreover, we find no 

additional monitoring costs are necessary to comply with this

final action; however, as in any other rule, EGU owners or 

operators may choose to conduct additional monitoring (and incur 

its expense) for their own purposes.

E. What are the economic and employment impacts?

Because we expect that electric power companies would 

install the same or similar control technologies to meet the 

standards finalized in this action as they would have chosen to 

comply with the previously finalized MATS standards, we do not 

anticipate that this final action will result in significant 

changes in emissions, energy impacts, costs, benefits, or 
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economic impacts. Likewise, we believe this action will not have 

any impacts on the price of electricity, employment or labor 

markets, or the U.S. economy.

F. What are the benefits of the final standards?

As previously stated, the EPA anticipates the power sector 

will not incur significant compliance costs or savings as a 

result of this action and we do not anticipate any significant 

emission changes resulting from this action. Therefore, there 

are no direct monetized benefits or disbenefits associated with 

this action.

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review

Under Executive Order (EO) 12866 (58 FR 51735; October 4, 

1993), this action is a “significant regulatory action” because 

it “raises novel legal or policy issues.” Accordingly, the EPA 

submitted this action to the Office of Management and Budget 

(OMB) for review under Executive Orders 12866 and 13563 (76 FR 

3821; January 21, 2011) and any changes made in response to OMB 

recommendations have been documented in the docket for this 

action.
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In addition, the EPA prepared an analysis of the potential 

costs and benefits associated with this action. This analysis is 

contained in the “Economic Impact Analysis for the Final

Reconsideration of the Mercury and Air Toxics Standards” found 

in rulemaking docket EPA-HQ-OAR-2009-0234. Because our analysis 

shows that new electricity generating units would choose to 

install the same control technology in order to meet the revised 

emission limits as would have been necessary to meet the 

previously finalized MATS standards, we project that this action

will result in no significant change in costs, emission 

reductions, or benefits.

B. Paperwork Reduction Act

This action does not impose any new information collection 

burden. Today’s action does not change the information 

collection requirements previously finalized and, as a result, 

does not impose any additional burden on industry. However, OMB 

has previously approved the information collection requirements 

contained in the existing regulations (see 77 FR 9304) under the 

provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et

seq. and has assigned OMB control number 2060-0567). The OMB 

control numbers for EPA’s regulations are listed in 40 CFR part 

9 and 48 CFR chapter 15.
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C. Regulatory Flexibility Act

The Regulatory Flexibility Act generally requires an agency 

to prepare a regulatory flexibility analysis of any rule subject 

to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute unless the 

agency certifies that the rule will not have a significant 

economic impact on a substantial number of small entities. Small 

entities include small businesses, small not-for-profit 

enterprises, and small governmental jurisdictions.

For purposes of assessing the impacts of today’s action on 

small entities, a small entity is defined as: (1) a small 

business as defined by the Small Business Administration’s (SBA) 

regulations at 13 CFR 121.201; (2) a small governmental 

jurisdiction that is a government of a city, county, town, 

school district, or special district with a population of less 

that 50,000; and (3) a small organization that is any not-forprofit enterprise which is independently owned and operated and

is not dominant in its field. Categories and entities 

potentially regulated by the final rule with applicable NAICS 

codes are provided in the Supplementary Information section of 

this action.

According to the SBA size standards for NAICS code 221122 
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Utilities-Fossil Fuel Electric Power Generation, a firm is small 

if, including its affiliates, it is primarily engaged in the 

generation, transmission, and or distribution of electric energy 

for sale and its total electric output for the preceding fiscal 

year did not exceed 4 million MWh.

After considering the economic impacts of today’s action on 

small entities, I certify that the notice 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. We have therefore concluded that today’s 

action will not result in a significant economic impact on a 

substantial number of small entities.

D. Unfunded Mandates Reform Act

This action contains no Federal mandates under the 

provisions of Title II of the Unfunded Mandates Reform Act of 

1995 (UMRA), 2 U.S.C. 1531-1538 for State, local, or tribal 

governments or the private sector. The action imposes no 

enforceable duty on any State, local, or tribal governments or 

the private sector. Therefore, this action is not subject to the 
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requirements of UMRA sections 202 or 205.

This action is also not subject to the requirements of UMRA 

section 203 because it contains no regulatory requirements that 

might significantly or uniquely affect small governments because 

it contains no requirements that apply to such governments or 

impose obligations upon them.

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, as specified in EO 13132. None of 

the affected facilities are owned or operated by state 

governments, and the requirements discussed in today’s notice 

will not supersede state regulations that are more stringent.

Thus, EO 13132 does not apply to today’s notice of 

reconsideration.

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

This action does not have tribal implications. It will not 

have substantial direct effects on tribal governments, on the 

relationship between the Federal government and Indian tribes, 
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or on the distribution of power and responsibilities between the 

Federal government and Indian tribes, as specified in EO 13175. 

No affected facilities are owned or operated by Indian tribal 

governments. Thus, EO 13175 does not apply to today’s action.

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

This action is not subject to EO 13045 (62 FR 19885; April 

23, 1997) because it is not economically significant as defined 

in EO 12866. The EPA has evaluated the environmental health or 

safety effects of the final MATS on children. The results of the 

evaluation are discussed in that final rule (77 FR 9304; 

February 16, 2012) and are contained in rulemaking docket EPAHQ-OAR-2009-0234.

H. Executive Order 13211: Actions that Significantly Affect 

Energy Supply, Distribution, or Use

This action is not a “significant energy action” as defined 

in EO 13211 (66 FR 28355; May 22, 2001) because it is not likely 

to have a significant adverse effect on the supply, 

distribution, or use of energy. Further, we conclude that 

today’s action is not likely to have any adverse energy effects 

because it is not expected to impose any additional regulatory 

requirements on the owners of affected facilities.
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I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

Advancement Act (NTTAA) of 1995 (Public Law 104-113; 15 U.S.C. 

272 note) directs EPA to use voluntary consensus standards in 

their regulatory and procurement activities unless to do so 

would be inconsistent with applicable law or otherwise 

impracticable. Voluntary consensus standards are technical 

standards (e.g., material specifications, test methods, sampling 

procedures, business practices) developed or adopted by one or 

more voluntary consensus bodies. The NTTAA requires EPA to 

provide Congress, through the OMB, with explanations when EPA 

decides not to use available and applicable voluntary consensus 

standards.

During the development of the final MATS rule, the EPA 

searched for voluntary consensus standards that might be 

applicable. The search identified three voluntary consensus 

standards that were considered practical alternatives to the 

specified EPA test methods. An assessment of these and other 

voluntary consensus standards is presented in the preamble to 

the final MATS rule (77 FR 9441; February 16, 2012). Today’s 

action does not make use of any additional technical standards 

beyond those cited in the final MATS rule. Therefore, the EPA is 
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not considering the use of any additional voluntary consensus 

standards for this action.

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-income 

Populations

Executive Order 12898 (59 FR 7629; February 16, 1994) 

establishes federal executive policy on environmental justice. 

Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental 

justice part of their mission by identifying and addressing, as 

appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and 

activities on minority populations and low-income populations in 

the United States.

The EPA has determined that this action will not have 

disproportionately high and adverse human health or 

environmental effects on minority or low-income populations 

because it does not affect the level of protection provided to 

human health or the environment. Our analysis shows that new 

EGUs would choose to install the same control technology in 

order to meet the revised emission limits as would have been 

necessary to meet the previously finalized standard. Under the 
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relevant assumptions, we project that this action will result in 

no significant change in emission reductions.

K. Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801 et seq., as 

added by the Small Business Regulatory Enforcement Fairness Act 

of 1996, generally provides that before a rule may take effect, 

the agency promulgating the rule must submit a rule report, 

which includes a copy of the rule, to each House of the Congress 

and to the Comptroller General of the United States. The EPA 

will submit a report containing this final action and other 

required information to the U.S. Senate, the U.S. House of 

Representatives, and the Comptroller General of the United 

States prior to publication of the rule in the Federal Register. 

A major rule cannot take effect until 60 days after it is 

published in the Federal Register. This action is not a “major 

rule” as defined by 5 U.S.C. 804(2). This rule will be effective 

[INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL 

REGISTER].
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List of Subjects in 40 CFR Parts 60 and 63

Environmental protection, Administrative practice and 

procedure, Air pollution control, Hazardous substances, 

Intergovernmental relations, Reporting and recordkeeping 

requirements.

Dated: 

______________,

Bob Perciasepe

Acting Administrator.
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For the reasons discussed in the preamble, 40 CFR parts 60 and 

63 are amended 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. Amend § 60.41Da by revising the definitions of “coal” and 

“integrated gasification combined cycle electric utility steam 

generating unit,” and by adding the definition of “natural gas”

in alphabetical order to read as follows:

§ 60.41Da Definitions.

* * * * *

Coal means all solid fuels classified as anthracite, bituminous, 

subbituminous, or lignite by the American Society of Testing and 

Materials in ASTM D388 (incorporated by reference, see §60.17) 

and coal refuse. Synthetic fuels derived from coal for the 

purpose of creating useful heat, including but not limited to 

solvent-refined coal, gasified coal, coal-oil mixtures, and 

coal-water mixtures are included in this definition for the 

purposes of this subpart.

* * * * *

Integrated gasification combined cycle electric utility steam 
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generating unit or IGCC electric utility steam generating unit

means an electric utility combined cycle gas turbine that is 

designed to burn fuels containing 50 percent (by heat input) or 

more solid-derived fuel not meeting the definition of natural 

gas. The Administrator may waive the 50 percent solid-derived 

fuel requirement during periods of the gasification system 

construction, startup and commissioning, shutdown, or repair. No 

solid fuel is directly burned in the unit during operation.

* * * * *

Natural gas means a fluid mixture of hydrocarbons (e.g., 

methane, ethane, or propane), composed of at least 70 percent 

methane by volume or that has a gross calorific value between 35 

and 41 megajoules (MJ) per dry standard cubic meter (950 and 

1,100 Btu per dry standard cubic foot), that maintains a gaseous 

state under ISO conditions. In addition, natural gas contains 

20.0 grains or less of total sulfur per 100 standard cubic feet. 

Finally, natural gas does not include the following gaseous 

fuels: landfill gas, digester gas, refinery gas, sour gas, blast 

furnace gas, coal-derived gas, producer gas, coke oven gas, or 

any gaseous fuel produced in a process which might result in 

highly variable sulfur content or heating value.

* * * * *
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3. Amend § 60.42Da by revising paragraphs (a), (b)(2), and 

(e)(1) to read as follows:

§ 60.42Da Standards for particulate matter (PM).

(a) Except as provided in paragraph (f) of this section, on and 

after the date on which the initial performance test is 

completed or required to be completed under §60.8, whichever 

date comes first, an owner or operator of an affected facility 

shall not cause to be discharged into the atmosphere from any 

affected facility for which construction, reconstruction, or 

modification commenced before March 1, 2005, any gases that 

contain PM in excess of 13 ng/J (0.03 lb/MMBtu) heat input.

(b) * * *

(2) An owner or operator of an affected facility that combusts 

only natural gas and/or synthetic natural gas that chemically 

meets the definition of natural gas is exempt from the opacity 

standard specified in paragraph (b) of this section.

* * * * *

(e) * * *

(1) On and after the date on which the initial performance test 

is completed or required to be completed under §60.8, whichever 

date comes first, the owner or operator shall not cause to be 

discharged into the atmosphere from that affected facility any 
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gases that contain PM in excess of the applicable emissions 

limit specified in paragraphs (e)(1)(i) or (ii) of this section.

(i) For an affected facility which commenced construction or 

reconstruction:

(A) 11 ng/J (0.090 lb/MWh) gross energy output; or

(B) 12 ng/J (0.097 lb/MWh) net energy output.

* * * * *

(ii) For an affected facility which commenced modification, the 

emission limits specified in paragraphs (c) or (d) of this 

section.

* * * * *

4. Amend § 60.48Da by revising paragraphs (f), (o) introductory 

text, (o)(1), (o)(2) introductory text, (o)(3) introductory 

text, (o)(3)(i), and (o)(4) introductory text 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 
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obtained during startup, shutdown, or malfunction periods. Daily 

averages are only calculated for boiler operating days that have 

out-of-control periods totaling no more than 6 hours of unit 

operation during which the standard applies. 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 or 

shutdown.

* * * * *

(o) Compliance provisions for sources subject to §60.42Da(c)(2), 

(d), or (e)(1)(ii). Except as provided for in paragraph (p) of 

this section, the owner or operator must demonstrate compliance 

with each applicable emissions limit according to the 

requirements in paragraphs (o)(1) through (o)(5) of this 

section.

(1) You must conduct a performance test to demonstrate initial 

compliance with the applicable PM emissions limit in §60.42Da by 

the applicable date specified in §60.8(a). Thereafter, you must 
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conduct each subsequent performance test within 12 calendar 

months following the date the previous performance test was 

required to be conducted. You must conduct each performance test 

according to the requirements in §60.8 using the test methods 

and procedures in §60.50Da. The owner or operator of an affected 

facility that has not operated for 60 consecutive calendar days 

prior to the date that the subsequent performance test would 

have been required had the unit been operating is not required 

to perform the subsequent performance test until 30 calendar 

days after the next boiler operating day. Requests for 

additional 30 day extensions shall be granted by the relevant 

air division or office director of the appropriate Regional 

Office of the U.S. EPA.

(2) You must monitor the performance of each electrostatic 

precipitator or fabric filter (baghouse) operated to comply with 

the applicable PM emissions limit in §60.42Da using a continuous 

opacity monitoring system (COMS) according to the requirements 

in paragraphs (o)(2)(i) through (vi) unless you elect to comply 

with one of the alternatives provided in paragraphs (o)(3) and 

(o)(4) of this section, as applicable to your control device.

* * * * *

(3) As an alternative to complying with the requirements of 
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paragraph (o)(2) of this section, an owner or operator may elect 

to monitor the performance of an electrostatic precipitator 

(ESP) operated to comply with the applicable PM emissions limit 

in §60.42Da using an ESP predictive model developed in

accordance with the requirements in paragraphs (o)(3)(i) through 

(v) of this section.

(i) You must calibrate the ESP predictive model with each PM 

control device used to comply with the applicable PM emissions 

limit in §60.42Da operating under normal conditions. In cases 

when a wet scrubber is used in combination with an ESP to comply 

with the PM emissions limit, the wet scrubber must be maintained 

and operated.

* * * * *

(4) As an alternative to complying with the requirements of 

paragraph (o)(2) of this section, an owner or operator may elect 

to monitor the performance of a fabric filter (baghouse) 

operated to comply with the applicable PM emissions limit in 

§60.42Da by using a bag leak detection system according to the 

requirements in paragraphs (o)(4)(i) through (v) of this 

section.

* * * * *

5. Amend § 60.49Da by:
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a. Revising paragraphs (a) introductory text;

b. Adding paragraph (a)(3)(iv); and

c. Revising paragraphs (a)(4), (b) introductory text, and (t).

The revised and added text reads as follows:

§ 60.49Da Emission monitoring.

(a) An owner or operator of an affected facility subject to the 

opacity standard in §60.42Da must monitor the opacity of 

emissions discharged from the affected facility to the 

atmosphere according to the applicable requirements in 

paragraphs (a)(1) through (4) of this section.

* * * * *

(3) * * *

(iv) If the maximum 6-minute opacity is less than 10 percent 

during the most recent Method 9 of appendix A–4 of this part 

performance test, the owner or operator may, as an alternative 

to performing subsequent Method 9 of appendix A–4 performance 

tests, elect to perform subsequent monitoring using a digital 

opacity compliance system according to a site-specific 

monitoring plan approved by the Administrator. The observations 

must be similar, but not necessarily identical, to the 

requirements in paragraph (a)(3)(iii) of this section. For 

reference purposes in preparing the monitoring plan, see OAQPS 
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“Determination of Visible Emission Opacity from Stationary 

Sources Using Computer-Based Photographic Analysis Systems.”

This document is available from the U.S. Environmental 

Protection Agency (U.S. EPA); Office of Air Quality and Planning 

Standards; Sector Policies and Programs Division; Measurement 

Policy Group (D243–02), Research Triangle Park, NC 27711. This 

document is also available on the Technology Transfer Network 

(TTN) under Emission Measurement Center Preliminary Methods.

* * * * *

(4) An owner or operator of an affected facility that is subject 

to an opacity standard under §60.42Da is not required to operate 

a COMS provided that affected facility meets the conditions in 

either paragraph (a)(4)(i) or (ii) of this section.

(i) The affected facility combusts only gaseous and/or liquid 

fuels (excluding residue oil) where the potential SO2 emissions 

rate of each fuel is no greater than 26 ng/J (0.060 lb/MMBtu), 

and the unit operates according to a written site-specific 

monitoring plan approved by the permitting authority. This 

monitoring plan must include procedures and criteria for 

establishing and monitoring specific parameters for the affected 

facility indicative of compliance with the opacity standard. For 

testing performed as part of this site-specific monitoring plan, 
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the permitting authority may require as an alternative to the 

notification and reporting requirements specified in §§60.8 and 

60.11 that the owner or operator submit any deviations with the 

excess emissions report required under §60.51Da(d).

(ii) The owner or operator of the affected facility installs, 

calibrates, operates, and maintains a particulate matter 

continuous parametric monitoring system (PM CPMS) according to 

the requirements specified in subpart UUUUU of part 63.

* * * * *

(b) The owner or operator of an affected facility must install, 

calibrate, maintain, and operate a CEMS, and record the output 

of the system, for measuring SO2 emissions, except where only 

gaseous and/or liquid fuels (excluding residual oil) where the

potential SO2 emissions rate of each fuel is 26 ng/J (0.060 

lb/MMBtu) or less are combusted, as follows:

* * * * *

(t) The owner or operator of an affected facility demonstrating 

compliance with the output-based emissions limit under §60.42Da 

must either install, certify, operate, and maintain a CEMS for 

measuring PM emissions according to the requirements of 

paragraph (v) of this section or install, calibrate, operate, 

and maintain a PM CPMS according to the requirements for new 
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facilities specified in subpart UUUUU of part 63 of this 

chapter. An owner or operator of an affected facility 

demonstrating compliance with the input-based emissions limit in 

§60.42Da may install, certify, operate, and maintain a CEMS for 

measuring PM emissions according to the requirements of 

paragraph (v) of this section.

* * * * *

6. Revise § 60.50Da paragraph (f) to read as follows:

§ 60.50Da Compliance determination procedures and methods.

* * * * *

(f) The owner or operator of an electric utility combined cycle 

gas turbine that does not meet the definition of an IGCC must

conduct performance tests for PM, SO2, and NOX using the 

procedures of Method 19 of appendix A–7 of this part. The SO2 and 

NOX emission rates calculations from the gas turbine used in 

Method 19 of appendix A–7 of this part are determined when the 

gas turbine is performance tested under subpart GG of this part. 

The potential uncontrolled PM emission rate from a gas turbine 

is defined as 17 ng/J (0.04 lb/MMBtu) heat input.

* * * * *

PART 63—NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS 

FOR SOURCE CATEGORIES
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7. The authority citation for 40 CFR Part 63 continues to read 

as follows:

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

8. In § 63.9982, revise paragraphs (a) introductory text, (b), 

and (c) to read as follows:

§ 63.9982 What is the affected source of this subpart?

(a) This subpart applies to each individual or group of two or 

more new, reconstructed, or existing affected source(s) as 

described in paragraphs (a)(1) and (2) of this section within a 

contiguous area and under common control.

* * * * *

(b) An EGU is new if you commence construction of the coal- or 

oil-fired EGU after May 3, 2011.

(c) An EGU is reconstructed if you meet the reconstruction 

criteria as defined in §63.2, and if you commence reconstruction 

after May 3, 2011.

* * * * *

9. In § 63.10000, revise paragraphs (c)(1)(iv) and (c)(2)(ii) to 

read as follows:

§ 63.10000 What are my general requirements for complying with 

this subpart?

* * * * *
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(c) * * *

(1) * * *

(iv) If your coal-fired or solid oil derived fuel-fired EGU or 

IGCC EGU does not qualify as a LEE for total non-mercury HAP

metals, individual non-mercury HAP metals, or filterable

particulate matter (PM), you must demonstrate compliance through 

an initial performance test and you must monitor continuous 

performance through either use of a particulate matter

continuous parametric monitoring system (PM CPMS), a PM CEMS, 

or, for an existing EGU, compliance performance testing repeated 

quarterly.

* * * * *

(c) * * *

(2) * * *

(ii) If your liquid oil-fired unit does not qualify as a LEE for 

total HAP metals (including mercury), individual metals 

(including mercury), or filterable PM you must demonstrate

compliance through an initial performance test and you must 

monitor continuous performance through either use of a PM CPMS, 

a PM CEMS, or, for an existing EGU, performance testing

conducted quarterly.

* * * * *
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10. Amend § 63.10005 by:

a. Revising paragraphs (d)(2)(ii) and (i)(4)(ii);

b. Adding paragraph (i)(5) and (i)(6).

The revised and added text read as follows:

§ 63.10005 What are my initial compliance requirements and by 

what date must I conduct them?

* * * * *

(d) * * *

(2) * * *

(ii) You must demonstrate continuous compliance with the PM CPMS 

site-specific operating limit that corresponds to the results of 

the performance test demonstrating compliance with the emission 

limit with which you choose to comply.

* * * * *

(i) * * *

(4) * * *

(ii) ASTM D4006-11, “Standard Test Method for Water in Crude Oil 

by Distillation,” including Annex A1 and Appendix A1.

* * * * *

(5) Use one of the following methods to obtain fuel moisture 

samples:

(i) ASTM D4177-95 (Reapproved 2010), “Standard Practice for 
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Automatic Sampling of Petroleum and Petroleum Products,”

including Annexes A1 through A6 and Appendices X1 and X2, or

(ii) ASTM D4057-06 (Reapproved 2011), “Standard Practice for

Manual Sampling of Petroleum and Petroleum Products,” including 

Annex A1.

(6) Should the moisture in your liquid fuel be more than 1.0 

percent by weight, you must

(i) Conduct HCl and HF emissions testing quarterly (and monitor 

site-specific operating parameters as provided in 

§63.10000(c)(2)(iii) or

(ii) Use an HCl CEMS and/or HF CEMS.

* * * * *

11. In § 63.10006, revise paragraph (c) to read as follows:

§ 63.10006 When must I conduct subsequent performance tests or 

tune-ups?

* * * * *

(c) Except where paragraphs (a) or (b) of this section apply, or 

where you install, certify, and operate a PM CEMS to demonstrate 

compliance with a filterable PM emissions limit, for liquid oil-

, solid oil-derived fuel-, coal-fired and IGCC EGUs, you must 

conduct all applicable periodic emissions tests for filterable 

PM, individual, or total HAP metals emissions according to Table 
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5 to this subpart, §63.10007, and §63.10000(c), except as 

otherwise provided in §63.10021(d)(1). 

* * * * *

12. In § 63.10007, revise paragraph (c) to read as follows:

§ 63.10007 What methods and other procedures must I use for the 

performance tests?

* * * * *

(c) If you choose the filterable PM method to comply with the PM 

emission limit and demonstrate continuous performance using a PM 

CPMS as provided for in §63.10000(c), you must also establish an 

operating limit according to §63.10011(b), §63.10023, and Tables 

4 and 6 to this subpart. Should you desire to have operating 

limits that correspond to loads other than maximum normal 

operating load, you must conduct testing at those other loads to 

determine the additional operating limits.

* * * * *

13. In § 63.10009, revise paragraphs (b)(2) and (b)(3) to read 

as follows:

§ 63.10009 May I use emissions averaging to comply with this 

subpart?

* * * * *

(b) * * *
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(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.

 =

∑ [∑ ( × )





]



 + ∑ ( × 

)





∑ [∑ ()





]



 + ∑ 





(. 2)

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 electrical 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 hourly rates 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 electrical output,

Rti = Total heat input or gross electrical 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.
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 =

∑ [∑ ( ×  × )





]



 + ∑ ( ×  × 

)





∑ [∑ ( × )





]



 + ∑  × 





(. 2)

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 electrical 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 electrical 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 
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3b to calculate the 90-day rolling average emissions daily.

 =

∑ [∑ ( × )





]



 + ∑ ( × 

)





∑ [∑ ()





]



 + ∑ 





(. 3)

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 electrical 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 hourly rates 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 electrical output,

Rti = Total heat input or gross electrical 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.
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 =

∑ [∑ ( ×  × )





]



 + ∑ ( ×  × 

)





∑ [∑ ( × )





]



 + ∑  × 





(. 3)

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 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 electrical 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 electrical output per pound of steam 

generated, from unit i that uses emissions testing.

* * * * *

14. In § 63.10010, revise paragraph (j)(1)(i) to read as 

follows:
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§ 63.10010 What are my monitoring, installation, operation, and 

maintenance requirements?

* * * * *

(j) * * *

(1) * * *

(i) Install and certify your HAP metals CEMS according to the 

procedures and requirements in your approved site-specific test 

plan as required in §63.7(e). 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. 

* * * * *

15. Amend § 63.10021 by adding paragraphs (c)(1) and (2) to read 

as follows:

§ 63.10021 How do I demonstrate continuous compliance with the 

emission limitations, operating limits, and work practice 

standards?

* * * * *

(c) * * *

(1) For any exceedance of the 30-boiler operating day PM CPMS 

average value from the established operating parameter limit for 

an EGU subject to the emissions limits in Table 1 to this 
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subpart, you must:

(i) Within 48 hours of the exceedance, visually inspect the air 

pollution control device (APCD);

(ii) If the inspection of the APCD identifies the cause of the 

exceedance, take corrective action as soon as possible, and 

return the PM CPMS measurement to within the established value; 

and

(iii) Within 45 days of the exceedance or at the time of the 

annual compliance test, whichever comes first, conduct a PM 

emissions compliance test to determine compliance with the PM 

emissions limit and to verify or re-establish the CPMS operating 

limit. You are not required to conduct any additional testing 

for any exceedances that occur between the time of the original 

exceedance and the PM emissions compliance test required under 

this paragraph.

(2) PM CPMS exceedances of the operating limit for an EGU 

subject to the emissions limits in Table 1 of this subpart

leading to more than four required performance tests in a 12-

month period (rolling monthly) constitute a separate violation 

of this subpart.

* * * * *

16. In § 63.10023, revise paragraph (b) to read as follows:
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§ 63.10023 How do I establish my PM CPMS operating limit and 

determine compliance with it?

* * * * *

(b) Determine your operating limit as provided in paragraph 

(b)(1) or (b)(2) of this section. You must verify an existing or 

establish a new operating limit after each repeated performance 

test.

(1) For an existing EGU, determine your operating limit based on 

the highest 1-hour average PM CPMS output value recorded during 

the performance test.

(2) For a new EGU, determine your operating limit as follows.

(i) If your PM performance test demonstrates your PM emissions 

do not exceed 75 percent of your emissions limit, you will use 

the average PM CPMS value recorded during the PM compliance 

test, the milliamp equivalent of zero output from your PM CPMS, 

and the average PM result of your compliance test to establish 

your operating limit. Calculate the operating limit by 

establishing a relationship of PM CPMS signal to PM 

concentration using the PM CPMS instrument zero, the average PM 

CPMS values corresponding to the three compliance test runs, and 

the average PM concentration from the Method 5 compliance test 

with the procedures in (b)(2)(i)(A) through (D) of this section.
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(A) Determine your PM CPMS instrument zero output with one of 

the following procedures.

(1) Zero point data for in-situ instruments should be obtained

by removing the instrument from the stack and monitoring ambient 

air on a test bench.

(2) Zero point data for extractive instruments should be

obtained by removing the extractive probe from the stack and 

drawing in clean ambient air.

(3) The zero point can also can be obtained by performing manual 

reference method measurements when the flue gas is free of PM 

emissions or contains very low PM concentrations (e.g., when 

your process is not operating, but the fans are operating or 

your source is combusting only natural gas) and plotting these 

with the compliance data to find the zero intercept.

(4) If none of the steps in paragraphs (A)(1) through (3) of 

this section are possible, you must use a zero output value 

provided by the manufacturer.

(B) Determine your PM CPMS instrument average () in milliamps, 

and the average of your corresponding three PM compliance test 

runs (), using equation 10.

̅=





∑ 

,  =





∑ 









(Eq. 10)
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Where:

Xi = the PM CPMS data points for run i of the performance test,

Yi = the PM emissions value (in lb/MWh) for run i of the 

performance test, and

n = the number of data points.

(C) With your PM CPMS instrument zero expressed in milliamps, 

your three run average PM CPMS milliamp value, and your three 

run average PM emissions value (in lb/MWh) from your compliance 

runs, determine a relationship of PM lb/MWh per milliamp with 

equation 11.

 =



(̅)

 (Eq. 11)

Where:

R = the relative PM lb/MWh per milliamp for your PM CPMS,

 = the three run average PM lb/MWh,

̅ = the three run average milliamp output from your PM CPMS, and

z = the milliamp equivalent of your instrument zero determined

from (b)(2)(i)(A) of this section.

(D) Determine your source specific 30-day rolling average 

operating limit using the PM lb/MWh per milliamp value from 

equation 11 in equation 12, below. This sets your operating 
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Page 73 of 93

limit at the PM CPMS output value corresponding to 75 percent of 

your emission limit.

 =  +

(. ×)



(Eq. 12)

Where:

OL = the operating limit for your PM CPMS on a 30-day rolling 

average, in milliamps,

L = your source PM emissions limit in lb/MWh,

z = your instrument zero in milliamps, determined from 

(b)(2)(i)(A) of this section, and

R = the relative PM lb/MWh per milliamp for your PM CPMS, from 

equation 11.

(ii) If your PM compliance test demonstrates your PM emissions 

exceed 75 percent of your emissions limit, you will use the 

average PM CPMS value recorded during the PM compliance test 

demonstrating compliance with the PM limit to establish your 

operating limit.

(A) Determine your operating limit by averaging the PM CPMS 

milliamp output corresponding to your three PM performance test 

runs that demonstrate compliance with the emission limit using 
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equation 13.

 =





∑ 





(Eq. 13)

Where:

Xi = the PM CPMS data points for all runs i,

n = the number of data points, and

Oh = your site specific operating limit, in milliamps.

(iii) Your PM CPMS must provide a 4-20 milliamp output and the

establishment of its relationship to manual reference method

measurements must be determined in units of milliamps.

(iv) Your PM CPMS operating range must be capable of reading PM 

concentrations from zero to a level equivalent to two times your 

allowable emission limit. If your PM CPMS is an auto-ranging 

instrument capable of multiple scales, the primary range of the 

instrument must be capable of reading PM concentration from zero 

to a level equivalent to two times your allowable emission

limit.

(v) During the initial performance test or any such subsequent

performance test that demonstrates compliance with the PM limit, 

record and average all milliamp output values from the PM CPMS 
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Page 75 of 93

for the periods corresponding to the compliance test runs.

(vi) For PM performance test reports used to set a PM CPMS 

operating limit, the electronic submission of the test report 

must also include the make and model of the PM CPMS instrument, 

serial number of the instrument, analytical principle of the 

instrument (e.g. beta attenuation), span of the instruments 

primary analytical range, milliamp value equivalent to the 

instrument zero output, technique by which this zero value was 

determined, and the average milliamp signal corresponding to 

each PM compliance test run.

* * * * *

17. In § 63.10030, revise paragraphs (b), (c), and (d) to read 

as follows:

§ 63.10030 What notifications must I submit and when?

* * * * *

(b) As specified in §63.9(b)(2), if you startup your EGU that is 

an affected source before April 16, 2012, you must submit an 

Initial Notification not later than 120 days after April 16, 

2012.

(c) As specified in §63.9(b)(4) and (b)(5), if you startup your

new or reconstructed EGU that is an affected source on or after 

April 16, 2012, you must submit an Initial Notification not 
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Page 76 of 93

later than 15 days after the actual date of startup of the EGU 

that is an affected source.

(d) When you are required to conduct a performance test, you 

must submit a Notification of Intent to conduct a performance 

test at least 30 days before the performance test is scheduled 

to begin.

* * * * *

18. Amend § 63.10042 by revising the definition of “Unit 

designed for coal > 8,300 Btu/lb subcategory” to read as 

follows:

§ 63.10042 What definitions apply to this subpart?

* * * * *

Unit designed for coal ≥ 8,300 Btu/lb subcategory means any 

coal-fired EGU that is not a coal-fired EGU in the “unit 

designed for low rank virgin coal” subcategory.

* * * * *

19. 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 For the following You must meet the Using these 
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is in this 

subcategory 

...

pollutants ... following emission 

limits and work 

practice standards 

...

requirements, 

as appropriate 

(e.g., 

specified 

sampling 

volume or test 

run duration) 

and 

limitations 

with the test 

methods in 

Table 5...

1. Coal-fired 

unit not low 

rank virgin 

coal.

a. Filterable 

particulate 

matter (PM)

9.0E-2 lb/MWh1 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:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

8.0E-3 lb/GWh

3.0E-3 lb/GWh

6.0E-4 lb/GWh

4.0E-4 lb/GWh

7.0E-3 lb/GWh

2.0E-3 lb/GWh

2.0E-2 lb/GWh

4.0E-3 lb/GWh

4.0E-2 lb/GWh 

5.0E-2 lb/GWh

Collect a 

minimum of 3 

dscm per run.

b. Hydrogen 

chloride (HCl)

1.0E-2 lb/MWh For Method 

26A, collect a 

minimum of 3 

dscm per run. 

For ASTM 

D6348-032 or 

Method 320, 

sample for a 

minimum of 1 
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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/MWh1 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:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

8.0E-3 lb/GWh

3.0E-3 lb/GWh

6.0E-4 lb/GWh

4.0E-4 lb/GWh

7.0E-3 lb/GWh

2.0E-3 lb/GWh

2.0E-2 lb/GWh

4.0E-3 lb/GWh

4.0E-2 lb/GWh 

5.0E-2 lb/GWh

Collect a 

minimum of 3 

dscm per run.

b. Hydrogen 

chloride (HCl)

1.0E-2 lb/MWh For Method 

26A, collect a 

minimum of 3 

dscm per run.

For ASTM 

D6348-032 or 

Method 320, 

sample for a 

minimum of 1 

hour.

OR

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

3

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/MWh4

9.0E-2 lb/MWh5

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:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

2.0E-2 lb/GWh

2.0E-2 lb/GWh

1.0E-3 lb/GWh

2.0E-3 lb/GWh

4.0E-2 lb/GWh

4.0E-3 lb/GWh

9.0E-3 lb/GWh

2.0E-2 lb/GWh

7.0E-2 lb/GWh 

3.0E-1 lb/GWh

Collect a 

minimum of 2 

dscm per run.

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 

D6348-032 or 

Method 320, 

sample for a 

minimum of 1 

hour.

OR
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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/MWh1 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:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

1.0E-2 lb/GWh

3.0E-3 lb/GWh

5.0E-4 lb/GWh

2.0E-4 lb/GWh

2.0E-2 lb/GWh

3.0E-2 lb/GWh

8.0E-3 lb/GWh

2.0E-2 lb/GWh

9.0E-2 lb/GWh

2.0E-2 lb/GWh

Collect a 

minimum of 2 

dscm per run.

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. 
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For ASTM 

D6348-032 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 

D6348-032 or 

Method 320, 

sample for a 

minimum of 1 

hour.

5. Liquid 

oil-fired 

unit – noncontinental 

(excluding 

limited-use 

liquid oilfired 

subcategory 

units).

a. Filterable 

particulate 

matter (PM)

2.0E-1 lb/MWh1 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:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

8.0E-3 lb/GWh

6.0E-2 lb/GWh

2.0E-3 lb/GWh

2.0E-3 lb/GWh

2.0E-2 lb/GWh

3.0E-1 lb/GWh

3.0E-2 lb/GWh

1.0E-1 lb/GWh

4.1E0 lb/GWh

2.0E-2 lb/GWh

Collect a 

minimum of 3 

dscm per run.

Mercury (Hg) 4.0E-4 lb/GWh For Method 30B 

sample volume 

determination 

(Section 

8.2.4), the 
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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 

D6348-032 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 

D6348-032 or 

Method 320, 

sample for a 

minimum of 1 

hour.

6. Solid oilderived fuelfired unit.a. Filterable 

particulate 

matter (PM)

3.0E-2 lb/MWh1 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 Collect a 
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metals:

Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

8.0E-3 lb/GWh

3.0E-3 lb/GWh

6.0E-4 lb/GWh

7.0E-4 lb/GWh

6.0E-3 lb/GWh

2.0E-3 lb/GWh

2.0E-2 lb/GWh

7.0E-3 lb/GWh

4.0E-2 lb/GWh

6.0E-3 lb/GWh

minimum of 3 

dscm per run.

b. Hydrogen 

chloride (HCl)

4.0E-4 lb/MWh For Method 

26A, collect a 

minimum of 3 

dscm per run. 

For ASTM 

D6348-032 or 

Method 320, 

sample for a 

minimum of 1 

hour.

OR

Sulfur dioxide 

(SO2)

3

1.0 lb/MWh SO2 CEMS. 

c. Mercury (Hg) 2.0E-3 lb/GWh Hg CEMS or 

Sorbent trap 

monitoring 

system only.

1 Gross electric output.

2 Incorporated by reference, see §63.14.

3 You may not use the alternate SO2 limit if your EGU does not 

have some form of FGD system (or, in the case of IGCC EGUs, some 

other acid gas removal system either upstream or downstream of 

the combined cycle block) and SO2 CEMS installed.

4 Duct burners on syngas; gross electric output.

5 Duct burners on natural gas; gross electric output.

20. 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
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As stated in §§63.9991, you must comply with the applicable 

operating limits:

If you demonstrate 

compliance using...

You must meet these operating 

limits...

1. PM CPMS for an 

existing EGU

Maintain the 30-boiler operating day 

rolling average PM CPMS output at or 

below the highest 1-hour average 

measured during the most recent 

performance test 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).

2. PM CPMS for a new 

EGU

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).

21. Revise footnote 4 of Table 5 to Subpart UUUUU of Part 63 to 

read as follows:

Table 5 to Subpart UUUUU of Part 63 — Performance Testing 

Requirements

* * * * *

4 When using ASTM D6348–03, the following conditions must be met: 
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(1) The test plan preparation and implementation in the Annexes 

to ASTM D6348–03, Sections A1 through A8 are mandatory; (2) For 

ASTM D6348–03 Annex A5 (Analyte Spiking Technique), the percent

(%)R must be determined for each target analyte (see Equation 

A5.5); (3) For the ASTM D6348–03 test data to be acceptable for 

a target analyte, %R must be 70% < R < 130%; and (4) The %R 

value for each compound must be reported in the test report and 

all field measurements corrected with the calculated %R value 

for that compound using the following equation:

22. Revise Table 6 to Subpart UUUUU of Part 63 to read as 

follows:

Table 6 to Subpart UUUUU of Part 63 — Establishing PM CPMS 

Operating Limits

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

requirements for establishing operating limits:

If you 

have an 

applicable 

emission 

limit 

for...

And you choose 

to establish PM 

CPMS operating 

limits, you 

must...

And... Using... According to 

the following 

procedures...

1. 

Filterable 

Particulat

e matter 

(PM), 

total nonmercury 

HAP 

metals, 

individual 

nonmercury 

HAP 

metals, 

total HAP 

metals, or 

individual 

Install, 

certify, 

maintain, and 

operate a PM 

CPMS for 

monitoring 

emissions 

discharged to 

the atmosphere 

according to 

§63.10010(h)(1)

.

Establish 

a sitespecific 

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 

performanc

e 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 

three run 

performance 

test.

3. Determine 

the highest 1-
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HAP metals 

for an 

existing 

EGU.

hour average 

PM CPMS 

measured 

during the 

performance 

test 

demonstrating 

compliance 

with the 

filterable PM 

or HAP metals 

emissions 

limitations.

2. 

Filterable 

Particulat

e matter 

(PM), 

total nonmercury 

HAP 

metals, 

individual 

nonmercury 

HAP 

metals, 

total HAP 

metals, or 

individual 

HAP metals 

for a new 

EGU.

Install, 

certify, 

maintain, and 

operate a PM 

CPMS for 

monitoring 

emissions 

discharged to 

the atmosphere 

according to 

§63.10010(h)(1)

.

Establish 

a sitespecific 

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 

performanc

e 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 
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filterable PM 

or HAP metals 

emissions 

limitations.

23. Revise Table 7 to Subpart UUUUU of Part 63 to read as 

follows:

Table 7 to Subpart UUUUU of Part 63 — Demonstrating Continuous 

Compliance

As stated in §63.10021, you must show continuous compliance with 

the emission limitations for affected sources according to the 

following:

If you use one of the 

following to meet applicable 

emissions limits, operating 

limits, or work practice 

standards ...

You demonstrate continuous 

compliance by ...

1. CEMS to measure filterable 

PM, SO2, HCl, HF, or Hg 

emissions, or using a sorbent 

trap monitoring system to 

measure Hg

Calculating the 30- (or 90-) 

boiler operating day rolling 

arithmetic average emissions rate 

in units of the applicable 

emissions standard basis at the 

end of each boiler operating day 

using all of the quality assured 

hourly average CEMS or sorbent 

trap data for the previous 30-

(or 90-) boiler operating days, 

excluding data recorded during 

periods of startup or shutdown.

2. PM CPMS to measure 

compliance with a parametric 

operating limit 

Calculating the 30- (or 90-) 

boiler operating day rolling 

arithmetic average of all of the 

quality assured hourly average PM 

CPMS output data (e.g., 

milliamps, PM concentration, raw 

data signal) collected for all 

operating hours for the previous 

30- (or 90-) boiler operating 
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days, excluding data recorded 

during periods of startup or 

shutdown.

3. Site-specific monitoring 

using CMS for liquid oil-fired 

EGUs for HCl and HF emission 

limit monitoring

If applicable, by conducting the 

monitoring in accordance with an 

approved site-specific monitoring 

plan.

4. Quarterly performance 

testing for coal-fired, solid 

oil derived fired, or liquid 

oil-fired EGUs to measure 

compliance with one or more

non-PM (or its alternative 

emission limits) applicable 

emissions limit in Table 1 or 

2, or PM (or its alternative 

emission limits) applicable 

emissions limit in Table 2

Calculating the results of the 

testing in units of the 

applicable emissions standard.

5. Conducting periodic 

performance tune-ups of your 

EGU(s) 

Conducting periodic performance 

tune-ups of your EGU(s), as 

specified in §63.10021(e).

6. Work practice standards for 

coal-fired, liquid oil-fired, 

or solid oil-derived fuelfired EGUs during startup 

Operating in accordance with 

Table 3. 

7. Work practice standards for 

coal-fired, liquid oil-fired, 

or solid oil-derived fuelfired EGUs during shutdown

Operating in accordance with 

Table 3. 

24. 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.
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§63.2 Definitions Yes. Additional terms 

defined in §63.10042.

§63.3 Units and 

Abbreviations

Yes.

§63.4 Prohibited 

Activities and 

Circumvention

Yes.

§63.5 Preconstruction 

Review and 

Notification 

Requirements

Yes.

§63.6(a), (b)(1)-

(b)(5), (b)(7), 

(c), (f)(2)-(3), 

(g), (h)(2)-

(h)(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.

§63.7(a), (b), 

(c), (d), (e)(2)-

(e)(9), (f), (g), 

and (h)

Performance 

Testing 

Requirements

Yes.

§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.
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§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)-(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)

-(ix)

Other CMS 

requirements

Yes.

§63.10(b)(3),and 

(d)(3)-(5)

No.

§63.10(c)(7) Additional 

recordkeeping 

requirements for 

CMS – identifying 

exceedances and 

excess emissions

Yes.
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Page 91 of 93

§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.

§63.13-63.16 Addresses, 

Incorporation by 

Reference, 

Availability of 

Information, 

Performance Track 

Provisions

Yes.

§63.1(a)(5),(a)(7

)-(a)(9), (b)(2), 

(c)(3)-(4), (d), 

63.6(b)(6), 

(c)(3), (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)-(4), 

(c)(9).

Reserved No.
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25. Revise sections 4.1 and 5.2.2.2 to Appendix A to Subpart 

UUUUU of Part 63 to read as follows:

Appendix A to Subpart UUUUU – Hg Monitoring Provisions

* * * * *

4.1 Certification Requirements. All Hg CEMS and sorbent trap 

monitoring systems and the additional monitoring systems used to 

continuously measure Hg emissions in units of the applicable 

emissions standard in accordance with this appendix must be 

certified in a timely manner, such that the initial compliance 

demonstration is completed no later than the applicable date in 

§63.9984(f).

* * * * *

5.2.2.2 The same RATA performance criteria specified in Table A2 for Hg CEMS also apply to the annual RATAs of the sorbent trap 

monitoring system.

* * * * *

26. Revise section 3.1.2.1.3 and correct the heading to section 

5.3.4 Conditional Data Validation to Appendix B to Subpart UUUUU 

of Part 63 to read as follows:

Appendix B to Subpart UUUUU – HCl and HF Monitoring Provisions

* * * * *

3.1.2.1.3 For the ASTM D6348–03 test data to be acceptable for 
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Page 93 of 93

a target analyte, %R must be 70% ≤ R ≤ 130%; and

* * * * *

5.3.3 Conditional Data Validation

* * * * *