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EO12866_MATS_Reconsideration_2060-AR62_Proposal_20121115 

 6560-50-P 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Parts 60 and 63 

EPA-HQ-OAR-2009-0234; EPA-HQ-OAR-2011-0044 [FRL-9733-2] 

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: Proposed rules; notice of public hearing. 

SUMMARY: On February 16, 2012, pursuant to sections 111 and 112 

of the Clean Air Act (CAA), the EPA published the final rules 

entitled “National Emission Standards for Hazardous Air 

Pollutants from Coal- and Oil-fired Electric Utility Steam 

Generating Units and Standards of Performance for Fossil-FuelFired Electric Utility, Industrial-Commercial-Institutional, and 

Small Industrial-Commercial-Institutional Steam Generating 

Units.” The National Emission Standards for Hazardous Air 

Pollutants (NESHAP) rule issued pursuant to CAA section 112 is 

referred to as the Mercury and Air Toxics Standards (MATS), and 
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the New 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 MATS and the Utility NSPS. In this notice, the EPA is 

announcing reconsideration of certain new source standards for 

MATS, the requirements applicable during periods of startup and 

shutdown for MATS, the startup and shutdown provisions related 

to the particulate matter (PM) standard in the Utility NSPS, and 

certain revisions to the definitional and monitoring provisions 

of the Utility NSPS. We are also proposing certain technical 

corrections to both MATS and the Utility NSPS. 

We seek comment only on the aspects of the final MATS and 

Utility NSPS rules specifically identified in this notice. We 

are not opening for reconsideration any other provisions of MATS 

or the Utility NSPS at this time. 

DATES: Comments. Comments must be received on or before [INSERT 

DATE 30 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. Because 

of the need to resolve the issues identified in this notice in a 

timely manner, the EPA does not intend to grant requests for 

extensions beyond this date. 

Public Hearing. If anyone contacts the EPA by [INSERT DATE 10 
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DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER] requesting to 

speak at a public hearing, the EPA will hold a public hearing on 

December 18, 2012. If a public hearing is held, it will be held 

from 9:00 a.m. to 7:00 p.m., Eastern time, in Room 1153 EPA East 

Hearing room, 1201 Constitution Avenue NW, Washington, DC 20460, 

(202) 564-1657. For further information on the public hearing 

and requests to speak, see the ADDRESSES section of this 

preamble. 

ADDRESSES: Comments. Submit your comments, identified by Docket 

ID. No. EPA-HQ-OAR-2011-0044 (NSPS action) or Docket ID No. EPAHQ-OAR-2009-0234 (NESHAP/MATS action), by one of the following 

methods: 

• http://www.regulations.gov. Follow the instructions for 

submitting comments. 

• http://www.epa.gov/oar/docket.html. Follow the 

instructions for submitting comments on the EPA Air and 

Radiation Docket Web Site. 

• E-mail: Comments may be sent by electronic mail (e-mail) 

to a-and-r-docket@epa.gov, Attention EPA-HQ-OAR-2011-0044 

(NSPS action) or EPA-HQ-OAR-2009-0234 (NESHAP/MATS 

action). 
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• Fax: Fax your comments to: (202) 566-9744, Docket ID No. 

EPA-HQ-OAR-2011-0044 (NSPS action) or Docket ID No. EPAHQ-OAR-2009-0234 (NESHAP/MATS action). 

• Mail: Send your comments on the NESHAP/MATS action to: 

EPA Docket Center (EPA/DC), Environmental Protection 

Agency, Mailcode: 2822T, 1200 Pennsylvania Ave., NW, 

Washington, DC 20460, Docket ID No. EPA-HQ-OAR-2009-0234. 

Send your comments on the NSPS action to: EPA Docket 

Center (EPA/DC), Environmental Protection Agency, 

Mailcode: 2822T, 1200 Pennsylvania Ave., NW, Washington, 

DC 20460, Docket ID. EPA-HQ-OAR-2011-0044. Please include 

a total of two copies. In addition, please mail a copy of 

your comments on the information collection provisions to 

the Office of Information and Regulatory Affairs, OMB, 

Attn: Desk Officer for EPA, 725 17th St., NW, Washington, 

DC 20503. 

• Hand Delivery or Courier: Deliver your comments to: EPA 

Docket Center, EPA West, Room 3334, 1301 Constitution 

Ave., NW, Washington, DC 20460. Please include a total of 

two copies. Such deliveries are only accepted during the 

Docket’s normal hours of operation (8:30 a.m. to 4:30 
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p.m., Monday through Friday, excluding legal holiday), 

and special arrangements should be made for deliveries of 

boxed information. 

Instructions. All submissions must include agency name and 

respective docket number or Regulatory Information Number (RIN) 

for this rulemaking. All comments will be posted without change 

and may be made available online at http://www.regulations.gov, 

including any personal information provided, unless the comment 

includes information claimed to be confidential business 

information (CBI) or other information whose disclosure is 

restricted by statute. Do not submit information that you 

consider to be CBI or otherwise protected through 

http://www.regulations.gov or e-mail. The 

http://www.regulations.gov web site is an “anonymous access” 

system, which means the EPA will not know your identity or 

contact information unless you provide it in the body of your 

comment. If you send an e-mail comment directly to the EPA 

without going through http://www.regulations.gov, your e-mail 

address will be automatically captured and included as part of 

the comment that is placed in the public docket and made 

available on the Internet. If you submit an electronic comment, 
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the EPA recommends that you include your name and other contact 

information in the body of your comment and with any disk or CDROM you submit. If the EPA cannot read your comment due to 

technical difficulties and cannot contact you for clarification, 

the EPA may not be able to consider your comment. Electronic 

files should avoid the use of special characters, any form of 

encryption, and be free of any defects or viruses. 

Public Hearing. If anyone contacts EPA by [INSERT DATE 10 DAYS 

AFTER PUBLICATION IN THE FEDERAL REGISTER] requesting to speak 

at a public hearing, the EPA will hold a public hearing on 

December 18, 2012. If a public hearing is held, it will be held 

from 9:00 a.m. to 7:00 p.m., Eastern time in Room 1153 EPA East 

Hearing room, 1201 Constitution Avenue NW, Washington, DC 20460, 

202-564-1657. A lunch break is scheduled from 12:00 p.m. - 1:00 

p.m. Visitors must go through a metal detector, sign in with the 

security desk, be accompanied by an employee and show 

identification to enter the building. Contact Pamela Garrett at 

(919) 541-7966 or at garrett.pamela@epa.gov to request a 

hearing, to determine if a hearing will be held and to register 

to speak if a hearing is held. If no one contacts the EPA 

requesting to speak at a public hearing concerning this proposed 
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rule by [INSERT DATE 10 DAYS AFTER PUBLICATION IN THE FEDERAL 

REGISTER], the hearing will be cancelled without further notice. 

If a hearing is held, the last day to register to present oral 

testimony in advance will be Friday, December 14, 2012. The 

public hearing will provide interested parties the opportunity 

to present data, views, or arguments concerning this notice. The 

record for this action will remain open for 30 days after the 

date of the hearing to provide an opportunity for submission of 

rebuttal and supplementary information. We will also specify the 

date and time of the public hearings on 

http://www.epa.gov/airquality/powerplanttoxics/actions.html and 

http://www.epa.gov/ttn/atw/utility/utilitypg.html. 

Docket. All documents in the docket are listed in the 

http://www.regulations.gov index. Although listed in the index, 

some information is not publicly available (e.g., CBI or other 

information whose disclosure is restricted by statute). Certain 

other material, such as copyrighted material, will be publicly 

available only in hard copy form. Publicly available docket 

materials are available either electronically in 

http://www.regulations.gov or in hard copy at the EPA Docket 

Center, Room 3334, 1301 Constitution Avenue, NW, Washington, DC. 
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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 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; E-mail 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 

Standards, U.S. Environmental Protection Agency, Research 

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

541-4003; Fax number (919) 541-5450; E-mail address: 

fellner.christian@epa.gov. 

SUPPLEMENTARY INFORMATION:

Outline. The information presented in this preamble is organized 

as follows: 

I. General Information 
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A. Does this reconsideration notice apply to me? 

B. What should I consider as I prepare my comments to the EPA? 

C. How do I obtain a copy of this document and other related 

information? 

II. Background 

III. Today’s Action 

IV. Discussion of Provisions Subject to Reconsideration – 

NESHAP/MATS 

A. New Source MATS Emission Limits 

B. Eligibility to be a New Source 

C. Startup and Shutdown Provisions 

V. Discussion of Provisions Subject to Reconsideration – Utility 

NSPS 

VI. Technical Corrections and Clarifications 

VII. Impacts of this Proposed Rule 

A. What are the air impacts? 

B. What are the energy impacts? 

C. What are the compliance costs? 

D. What are the economic and employment impacts? 

E. What are the benefits of the proposed 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 

Environmental Health 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 

I. General Information
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A. Does this reconsideration notice apply to me? 

Categories and entities potentially affected by today’s 

notice 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 

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 
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for the entity or your EPA regional representative as listed in 

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

B. What should I consider as I prepare my comments to the EPA? 

Do not submit information containing CBI to the EPA through 

http://www.regulations.gov or e-mail. Send or deliver 

information identified as CBI only to the following address: 

Roberto Morales, OAQPS Document Control Officer (C404-02), 

Office of Air Quality Planning and Standards, U.S. Environmental 

Protection Agency, Research Triangle Park, North Carolina 27711, 

Attention: Docket ID EPA-HQ-OAR-2011-0044 (Utility NSPS) or 

Docket ID EPA-HQ-OAR-2009-0234 (NESHAP/MATS). Clearly mark the 

part or all of the information that you claim to be CBI. For CBI 

information in a disk or CD-ROM that you mail to the EPA, mark 

the outside of the disk or CD-ROM as CBI and then identify 

electronically within the disk or CD-ROM the specific 

information that is claimed as CBI. In addition to one complete 

version of the comment that includes information claimed as CBI, 

a copy of the comment that does not contain the information 

claimed as CBI must be submitted for inclusion in the public 

docket. Information so marked will not be disclosed except in 

accordance with procedures set forth in 40 CFR Part 2. 
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C. How do I obtain a copy of this document and other related 

information? 

In addition to being available in the docket, electronic 

copies of these proposed rules will be available on the 

Worldwide Web (WWW) through the Technology Transfer Network 

(TTN). Following signature, a copy of each proposed rule 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. 

II. Background 

The Administrator signed MATS and the Utility NSPS on 

December 16, 2011, and the final rules were published in the 

Federal Register at 77 FR 9304, February 16, 2012. Following 

promulgation of the final rules, the Administrator received 

petitions for reconsideration of numerous provisions of both 

MATS and the Utility NSPS pursuant to CAA section 307(d)(7)(B). 

Copies of the MATS 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. 

III. Today’s Action 
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Today, we are granting reconsideration of, proposing, and 

requesting comment on the following limited set of issues: (1) 

certain revised new source standards in MATS, (2) requirements 

applicable during periods of startup and shutdown in MATS, (3) 

startup and shutdown provisions related to the PM standard in 

the Utility NSPS, and (4) definitional and monitoring provisions 

in the Utility NSPS. We are also proposing certain technical 

corrections to both MATS and the Utility NSPS. 

This notice is limited to the specific issues identified in 

this notice. We will not respond to any comments addressing any 

other provisions of MATS or the Utility NSPS.1

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

the benefits of the final rule are minor. We expect that source 

owners and operators will install and operate the same or 

similar control technologies to meet the proposed revised 

standards in this notice as they would have chosen to comply 

with the standards in the February 2012 final rule.2 

 

1

 The recent decision by the U.S. Court of Appeals for the DC 

Circuit regarding the Cross State Air Pollution Rule (CSAPR) has 

no impact on the issues being reconsidered in this action.

2

 Because, on an individual EGU-by-EGU basis we anticipate very 

similar costs, any changes to the baseline since we finalized 
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IV. Discussion of Provisions Subject to Reconsideration – 

NESHAP/MATS 

A. New Source MATS Emission Limits

The EPA received petitions requesting reconsideration of 

aspects of the new source emission limits in the final MATS 

rule. We are granting reconsideration of certain new source 

emission limits, as discussed below, and we invite comment on 

the proposed provisions in today’s notice. 

1. Certain New Source Limits – Use of Data in the Record 

The EPA received petitions for reconsideration asserting 

that the Agency did not use all the data in the record from the 

best performing sources in establishing certain final new source 

emission limits for coal- and oil-fired electric utility steam 

generating units (EGUs). Specifically, the petitioners 

maintained that the EPA did not consider all of the data in the 

record when establishing emission standards for filterable PM 

and hydrogen chloride (HCl) applicable to new coal-fired EGUs 

and for filterable PM applicable to new solid oil-derived fuelfired EGUs. 

 

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

impact this determination. 
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In light of petitioners’ assertions, we reviewed the 

available emissions information in the record for all the new 

source standards. We determined that we did not use all the data 

in the record in establishing the new source emission limits for 

filterable PM and HCl applicable to new coal-fired EGUs and for 

filterable PM applicable to new solid oil-derived fuel-fired 

EGUs. We also identified a few additional new source limits for 

which we did not use all of the data in the record when setting 

the standards in the final rule. We are proposing to revise the 

sulfur dioxide (SO2) limit applicable to solid oil-derived fuelfired EGUs, the filterable PM limit applicable to continental 

liquid oil-fired EGUs, and the lead and selenium limits 

applicable to coal-fired EGUs based on consideration of all the 

data in the record from the best performing sources for the 

pollutants at issue.3

 We solicit comment on the revised 

standards. Additional details on the proposed emission limits 

 

3

 We also solicit comment on possible revisions to the Hg limit 

applicable to low rank virgin coal-fired EGUs based on 

additional data in the record. See “Reconsideration of the 

National Emission Standards for Hazardous Air Pollutants 

(NESHAP) Maximum Achievable Control Technology (MACT) Floor 

Analysis for Coal- and Oil-fired Electric Utility Steam 

Generating Units, Proposed Rule” in rulemaking docket EPA-HQOAR-2009-0234; “MATS Reconsideration: Beyond-the-Floor 

Memorandum” available in rulemaking docket EPA-HQ-OAR-2009-0234. 
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can be found in the memo “Reconsideration of the National 

Emission Standards for Hazardous Air Pollutants (NESHAP) Maximum 

Achievable Control Technology (MACT) Floor Analysis for Coaland Oil-fired Electric Utility Steam Generating Units, Proposed 

Rule” in rulemaking docket EPA-HQ-OAR-2009-0234. 

The proposed revised new source CAA section 112(d) emission 

standards are presented in tables 1 and 2 of this preamble. The 

Agency derived these limits by first calculating the floor 

standards and then assessing whether a more stringent beyondthe-floor standard is appropriate. As explained further below, 

as to the standards we are proposing to revise, we are proposing 

a beyond-the-floor standard for HCl for new coal-fired EGUs, but 

we are not proposing beyond-the-floor standards for the other 

pollutants and subcategories. 

2. SO2 Limit for New Coal-fired EGUs – Reliance on Industrial 

Boiler Emission Data 

We are also reconsidering the SO2 standard for new coalfired EGUs. The Agency received a petition asserting that the 

final alternative SO2 emission limit was developed using, as the 

best performing source, a unit that is 25 MW in capacity. In 

order to be classified as an EGU, and thus subject to MATS, a 
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unit must be greater than 25 MW in capacity. A unit that is 25 

MW or less is likely an industrial boiler and would be subject 

to the Industrial-Commercial-Institutional Boiler NESHAP, not 

MATS. 

At the time of the final rule, we believed the unit on 

which we based the SO2 standard for new coal-fired EGUs was an 

EGU. After we received the petition for reconsideration, we reexamined the record and determined that the unit was, in fact, 

an industrial boiler and not an EGU. 

As an initial matter, nothing in the CAA precludes the EPA 

from identifying a source in another source category as the best 

controlled similar source. However, we believe that it is 

appropriate in this case, where we have considerable data on 

EGUs, to base the new source standard on the best performing 

unit that is an EGU. This is also consistent with our intent in 

the final rule, as we thought the unit we had selected was, in 

fact, an EGU. For these reasons, we are reconsidering the SO2

standard for new coal-fired EGUs. We have reviewed the emissions 

data and identified the best performing EGU upon which to base 

the proposed SO2 standard. The proposed limit is presented in 
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table 2 of this preamble. We solicit comment on the revised 

limit and the methods used to establish this limit.

3. Hg Limit for New Coal-fired EGUs Designed for Coal ≥ 8300 

Btu/lb – Measurement Issues 

The EPA is also reconsidering the emission limit for Hg for 

new coal-fired EGUs in the units designed for the coal ≥ 8300 

Btu/lb (non-low rank virgin coal) subcategory. Some petitioners 

asserted that this limit, as finalized, was too low for 

emissions to be reliably measured in a manner that would allow 

sources to operate their control technology in a way that 

ensures compliance with the standard. Specifically, petitioners 

maintained that sorbent trap monitoring systems could not 

provide sufficiently timely Hg data at the new source level for 

sources to make adjustments to the EGUs and attendant air 

pollution control devices (ACPDs) to ensure compliance with the 

standard and that Hg continuous emissions monitoring systems 

(CEMS) were not capable of measuring Hg at the new source limit. 

The petitioners indicated that reliable and frequent emission 

measurements are needed to maintain the operation of Hg control 

technology at performance levels set in the final rule. 

As we explained in the record to the final rule, owners and 
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operators of new EGUs in the non-low rank virgin coal 

subcategory could use the sorbent trap monitoring systems to 

demonstrate compliance with the new source Hg standard because 

of the potential for a longer sample collection period 

associated with sorbent traps and their inherent lower emissions 

detection capability. 

As described in the final rule, when establishing emission 

limits for pollutants, we calculated a representative detection 

limit (RDL) and then compared the UPL-determined emission floor 

with a value three times the RDL (3 X RDL), and we set the final 

limit at the higher of the two numbers. We did not follow that 

procedure for sorbent trap monitoring systems when setting Hg 

emission limits as we did not believe sorbent trap monitoring 

systems were constrained by method detection limits, since 

operators could increase the sample collection time up to 14 

days to guarantee collection of a measurable quantity of mercury 

with appropriate accuracy. We continue to believe that the 

promulgated Hg limit for the non-low rank virgin coal 

subcategory is measurable using a sorbent trap monitoring 

system. 

As noted, however, petitioners have indicated that the long 
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sorbent trap sampling times that may be necessary to measure at 

the final new source level do not allow sufficiently frequent 

emissions feedback such that a source could take corrective 

action and avoid violations of the emission limit within the 

prescribed compliance time. 

We understand that Hg emissions can vary over time, and we 

acknowledge the value of frequent feedback of emission 

measurements. We also understand that frequent feedback may be 

desirable and, at times, necessary to optimize the operation of 

generation or control technology in order to maintain emissions 

at or below the standard. The sorbent trap monitoring method 

required in the MATS rule allows sampling for as long as 14 

days. In the final rule, we assumed that most sources would 

leave the sorbent traps in as long as needed – up to 14 days - 

to ensure they had no measurement issues. Based on the petitions 

for reconsideration, we understand that sources will most likely 

use a shorter sampling period, perhaps as short as 30 minutes. 

The shorter sampling periods will provide more constant feedback 

on Hg emissions, which will help the source ensure that it is in 

compliance with the Hg emission limit, for which compliance is 

determined on a 30-day rolling average. 
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Given the petitioners’ stated need for more frequent Hg 

emissions information, we re-evaluated whether detection level 

issues arise when shorter sampling periods, such as 30 minutes, 

are employed by sorbent trap monitoring systems. Although the 

shorter sampling period is adequate to provide information 

needed to optimize the operation of Hg control technology, we 

believe the reduced sampling period results in a reduced 

quantity of collected Hg which constrains the sorbent trap 

monitoring system by a minimum detection limit. For additional 

information, see the memo “Determination of Representative 

Detection Level (RDL) and 3 X RDL Values for Mercury Measured 

Using Sorbent Trap Technologies” in rulemaking docket EPA-HQOAR-2009-0234. Specifically, we believe detection level issues 

may arise from using a sorbent trap when short sampling periods 

(e.g., 30 minutes) are used, and that, as such, the UPLcalculated floor value should be compared against the 3 X RDL 

value to account for the shorter sampling periods. We solicit 

comment on this proposed revised approach in light of the 

information provided by petitioners regarding the need for 

prompt Hg emissions information. 

Our review of the data in the record shows that for 
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reasonable, shorter sampling conditions - 30-minute samples 

obtained at a sampling rate of 0.5 liter per minute - the UPLdetermined new source Hg limit is less than the 3 X RDL value. 

Therefore, we are proposing to set the Hg limit for the non-low 

rank virgin coal subcategory at the 3 x RDL value. 

Although the value of the resulting limit we are proposing 

today is higher than that in the final rule, we do not expect 

this change to alter the emission control strategy of a new EGU, 

as both emission limits result in Hg removal efficiency in 

excess of 97 percent. However, the proposed change will improve 

EGU owners’ and operators’ ability to track emissions and take 

preemptive actions to ensure compliance. Based on information 

provided by the petitioners, our experience, and the National 

Institute of Standards and Technology's recently confirmed 

capability to certify Hg calibration gas generators down to 0.2 

micrograms per cubic meter (g/m3

), the proposed change in the Hg 

limit will also allow the option of using a Hg CEMS for process 

control and for determining compliance. 

Please refer to the memo “Data and Procedure for Handling 

Below Detection Level Data in Analyzing Various Pollutant 

Emissions Databases for MACT and RTR Emissions Limits” (docket 
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entry EPA-HQ-OAR-2009-0234-20062) for a discussion of the RDL 

approach generally, and the memo “Determination of 

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

Mercury Measured Using Sorbent Trap Technologies” (rulemaking 

docket EPA-HQ-OAR-2009-0234) for a discussion of our approach 

for establishing an RDL for Hg. The proposed limit is presented 

in table 1 of this preamble. 

4. Limits for New IGCC EGUs – Use of Permit Limits from 

Unconstructed IGCC EGUs 

We are granting reconsideration of the finalized new source 

integrated gasification combined cycle (IGCC) limits. The EPA 

used the permit limits from IGCC EGUs that are permitted but not 

yet constructed as the basis for some of the final new source 

IGCC emission limits. Some petitioners asserted that the EPA did 

not use this approach in the notice of proposed rulemaking and 

that they therefore were deprived of the opportunity to comment 

on this approach. 

Although we indicated that we considered establishing 

standards based on IGCC permits at proposal, we are granting 

reconsideration on the new source IGCC limits so that the public 

has an additional opportunity to comment on the limits and the 
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approach. 

Specifically, we request comment on the proposed new source 

IGCC standards, which are unchanged from the final standards 

promulgated for these units on February 16, 2012. These proposed 

new source limits are presented in tables 1 and 2 of this 

preamble. 

5. Beyond-the-floor Analysis 

The MACT floor level of control for new EGUs is based on 

the emission control that is achieved in practice by the best 

controlled similar source, as determined by the Agency, of each 

HAP for the different subcategories. After the EPA establishes 

MACT floor levels, CAA section 112(d)(2) requires the EPA to 

consider whether more stringent beyond-the-floor standards 

should be established. Under that section, the Agency must 

consider “the cost of achieving such emission reduction, and any 

non-air quality health and environmental impacts and energy 

requirements” before it may establish a standard that is based 

on a beyond-the-floor level of control. 

For most of the new source standards addressed in this 

proposal, we have not identified additional technologies or HAP 

emission reduction approaches that would achieve HAP reductions 
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greater than the new source floors for the subcategories, other 

than multiple controls in series (e.g., multiple scrubbers in 

series or multiple PM controls in series), which we consider to 

be unreasonable from a cost perspective. We are therefore 

proposing to adopt the floor level of control for all but one of 

these standards. We are proposing a beyond-the-floor standard 

for HCl emissions from coal-fired EGUs. Summaries of the EPA’s 

beyond-the-floor evaluations for the new source standards 

addressed in this proposal are provided below. Additional detail 

of these analyses, including a discussion of costs and non-air 

quality health and environmental impacts, is provided in the 

“MATS Reconsideration: Beyond-the-Floor Memorandum” available in 

rulemaking docket EPA-HQ-OAR-2009-0234. We request comment on 

all aspects of our beyond-the-floor analysis. Specifically, we 

solicit comment on whether there are any control technologies or 

HAP emission reduction practices that have been demonstrated to 

achieve HAP reductions at levels lower than the standards 

proposed in this notice consistently and in a cost-effective 

manner. Comments should include information on emissions, 

pollutant control efficiencies, operational reliability, current 

demonstrated applications, and costs. 
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a. Beyond-the-floor analysis for PM from coal-fired EGUs. It is 

commonly accepted that a baghouse fabric filter (FF) is the 

technology that provides the best level of PM emission reduction 

for coal-fired EGUs. Newly constructed coal-fired EGUs will be 

expected to install FFs to meet the new source NESHAP PM limit 

that we are proposing in this notice and the applicable NSPS 

limit. We have considered available options that would allow a 

new source to achieve greater emission reductions than those 

achieved in practice by the best controlled source. The EPA is 

aware that some EGUs have installed downstream secondary 

“polishing” PM control devices to provide for incremental PM 

reductions beyond what is achieved by the primary PM control 

device. However, those “polishing” PM control devices are most 

often installed for one of two purposes: (1) to augment the 

control of an underperforming or undersized primary control 

device or (2) to allow for injection of activated carbon or 

other powdered sorbent so that the fly ash and the sorbent 

remain separated for eventual storage, disposal, or re-use. 

Given that a new coal-fired EGU would have the opportunity to 

design the primary PM control device to meet the new source 

emission limit, we can see no justification for including in the 
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Page 27 of 110 

design a secondary downstream “polishing” PM control device. 

Such a device would add considerable cost to the project, and 

the incremental cost-effectiveness would not be reasonable. See 

“MATS Reconsideration: Beyond-the-Floor Memorandum” in 

rulemaking docket EPA-HQ-OAR-2009-0234. 

b. Beyond-the-floor analysis for Hg from new coal-fired EGUs 

designed for coal ≥ 8300 Btu/lb. The proposed new source Hg 

emission limit for EGUs firing non-low rank virgin coal is based 

on the use of the 3 X RDL approach. As explained above, there is 

concern that a lower emission limit could not be reliably 

measured with sufficient frequency to allow consistent and 

timely compliance. For this reason, we are not proposing a limit 

based on a beyond-the-floor level of control, and, instead, we 

are proposing to establish the standard at the MACT floor level. 

c. Beyond-the-floor analysis for SO2 emissions from coal-fired 

EGUs. The best performing source for SO2 emissions from a coalfired EGU is a circulating fluidized bed combustor (CFB) with 

limestone injection for SO2 control and a downstream circulating 

dry scrubber (CDS) for supplemental SO2 control. Because the EGU 

already employs a downstream “polishing” SO2 control device, we 

do not believe that installation of an additional “polishing” 
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control device would result in cost-effective reduction (in 

$/ton of incremental SO2 reduction) that would justify setting a 

beyond-the-floor emission limit. See “MATS Reconsideration: 

Beyond-the-Floor Memorandum” in rulemaking docket EPA-HQ-OAR2009-0234. 

d. Beyond-the-floor analysis for PM from solid oil-derived fuelfired EGUs. This analysis is very similar to that which was 

presented earlier for PM emissions from coal-fired EGUs. Given 

that a new solid oil-derived fuel-fired EGU would have the 

opportunity to design the primary PM control device to meet the 

new source emission limit, we can see no justification for 

including in the design a secondary downstream “polishing” PM 

control device. As with the coal-fired source, such a device 

would add considerable costs to the project, and the incremental 

cost-effectiveness would not be reasonable. 

e. Beyond-the-floor analysis for SO2 from solid oil-derived fuelfired EGUs. The best performing source for SO2 emissions from 

solid oil-derived fuel-fired EGUs is a CFB combustor with 

limestone injection for SO2 control. Additional SO2 control, 

beyond that which is obtained by the best controlled source, may 

be obtained by installing a downstream SO2 control device such as 
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a spray drier absorber (SDA)or wet-flue gas desulfurization 

(wet-FGD) scrubber or, as was the case with the best performing 

coal-fired unit, a CDS. However, as stated earlier, we believe 

that, in this case, the installation of additional downstream 

“polishing” control technologies does not result in costeffective control (in $/ton of incremental SO2 reduction) that 

would justify setting a beyond-the-floor emission limit. 

f. Beyond-the-floor analysis for PM from continental liquid oil 

fuel-fired EGUs. The proposed new source filterable PM emission 

limit for continental liquid oil-fired fuel is based on an EGU 

which uses an electrostatic precipitator (ESP). Distillate oilfired facilities do not need add-on PM controls, as their 

emissions are inherently low, and residual oil-fired units 

cannot use FFs for PM control due to concerns about bag 

contamination and fire safety. ESPs are the best filterable PM 

control technology for liquid oil fuel-fired EGUs. Given that a 

new continental liquid-oil fuel-fired EGU would have the 

opportunity to design the primary PM control device to meet the 

new source emission limit, we can see no justification for 

including in the design a secondary downstream “polishing” PM 

control device. Such a device would add considerable costs to 
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the project, and the incremental cost-effectiveness would not be 

reasonable. 

g. Beyond-the-floor analysis for HAP emissions from IGCC EGUs. 

We have no data upon which to assess whether or not technologies 

exist that can provide additional HAP control beyond the 

proposed new source emission limits for new IGCC units. 

Accordingly, we are not proposing to establish beyond-the-floor 

emission limitations for these pollutants for new IGCC units. We 

request comment on whether the use of any control technologies 

or practices have been demonstrated to consistently achieve in a 

cost-effective manner, emission levels for similar sources that 

are lower than those proposed for new IGCC sources in this 

proposal. Comments should include information on emissions, 

pollutant control efficiencies, operational reliability, current 

demonstrated applications, and costs. 

h. Beyond-the-floor analysis for HCl emissions from coal-fired 

EGUs. For HCl, the EPA’s revised floor analysis for coal units – 

discussed above – resulted in a revised MACT floor of 2.0E-2 

pound per megawatt-hour (lb/MWh). We have estimated that a new 

coal-fired EGU would need to remove HCl in the range of 81.0 to 

96.6 percent (depending upon the initial chlorine (Cl) content 
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of the fuel) in order to meet this revised MACT floor level of 

control for HCl emissions. We also note that it is reasonable to 

expect that in most, if not all, cases, advanced FGD control 

technology (such as a wet-FGD scrubber or a high efficiency SDA) 

would be required as a result of other federal requirements – 

specifically a prevention of significant deterioration (PSD) 

best available control technology (BACT) analysis. More detailed 

discussion may be found in the memo “MATS Reconsideration: 

Control Technology Needed to Meet New Source Limits” contained 

in rulemaking docket EPA-HQ-OAR-2009-0234. 

A high efficiency SDA is less costly than a wet-FGD, and we 

think it likely that some new sources will be able to comply 

with PSD/BACT requirements using that less expensive option.4

 For 

this reason, we believe that it is reasonable to assume the 

 

4

 New Source Review (NSR) permit requirements include, among 

other things, the application of BACT (best available control 

technology) under PSD. BACT control technology determinations 

and associated emission limit establishment involve case-by-case 

analyses and, such analyses take into account site-specific 

factors such as energy, environmental and economic impacts. For 

that reason, it is impossible to strictly predict the outcome of 

such analyses. However, based on recent BACT determinations for 

SO2 emissions from coal-fired EGUs, it is reasonable to expect 

that in most, if not all, cases, flue gas desulfurization 

control technologies (such as wet-FGD scrubbers or high 

efficiency spray drier absorbers) would be required. 
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minimum level of performance for HCl control from a new EGU will 

be equivalent to that of a well-performing SDA for purposes of 

the beyond-the-floor analysis. We examined the level of HCl 

control achieved by those EGUs from the 2010 utility information 

collection request (ICR) database that were equipped with SDA 

and we determined that those EGUs achieved HCl control in a 

range of 90 to 98 percent (coal-to-stack, depending on the coal 

Cl content).5

We, therefore, are proposing to set a beyond-the-floor HCl 

emission limit for new coal-fired EGUs at 1.0E-2 lb/MWh. We 

believe that a new EGU firing lower Cl-content coal would need 

to achieve a minimum of 90 percent control to meet this proposed 

limit and that a new EGU firing a higher Cl-content coal would 

need to achieve a minimum of 98 percent control to meet the 

limit. We believe that this beyond-the-floor emission limit is 

cost-effective because it does not involve additional cost, as 

we expect that any new unit will install at least a high 

efficiency SDA to comply with other CAA requirements. 

 

5

 Note that the HCl emission levels achieved are very similar for 

all EGUs. The difference observed in level of control 

(percentage) is due to the difference in chlorine levels seen in 

various coals.
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We also considered a beyond-the-floor emission limit by 

assuming installation of a wet-FGD scrubber, which generally 

achieves greater HCl reductions, but at a greater cost, than a 

high efficiency SDA. We understand that some new coal-fired EGUs 

will likely be required to install this type of advanced FGD 

technology for SO2 control. However, if the EGU is not required 

to install a wet-FGD scrubber from the PSD BACT determination 

for SO2, then the additional costs beyond those for a high 

efficiency SDA would be attributable to the achievement of 

additional HCl emission reductions, and the cost-effectiveness 

would not be reasonable. 

6. Proposed New Source Emission Limits 

For coal-fired EGUs, the final rule regulates HCl as a 

surrogate for acid gas HAP, with an alternative equivalent 

standard for SO2 as a surrogate for acid gas HAP for coal-fired 

EGUs with FGD systems installed and operational; filterable PM 

as a surrogate for non-mercury HAP metals, with total nonmercury HAP metals and individual non-mercury HAP metals as 

alternative equivalent standards; Hg; and organic HAP. For oilfired EGUs, the final rule regulates HCl and HF; filterable PM 

as a surrogate for total HAP metals, with individual HAP metals 
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as alternative equivalent standards; and organic HAP. The 

filterable PM, HCl, and Hg limits that we are proposing to 

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

proposing to revise are provided in table 2. We are soliciting 

comment on the revised new source emission limits proposed in 

this action. 

TABLE 1. PROPOSED EMISSION LIMITATIONS FOR NEW EGUS 

Subcategory 

Filterable 

particulate 

matter 

Hydrogen 

chloride Mercury 

New - Unit 

not designed 

for low rank 

virgin coal 

9.0E-2 lb/MWh 1.0E-2 lb/MWha 3.0E-3 lb/GWh 

New - Unit 

designed for 

low rank 

virgin coal 

9.0E-2 lb/MWh 1.0E-2 lb/MWha NR 

New – IGCC 7.0E-2 lb/MWhb

9.0E-2 lb/MWhc 2.0E-3 lb/MWhd 3.0E-3 lb/GWhe

New – Solid 

oil-derived 3.0E-2 lb/MWh NR NR 

New – Liquid 

oil - 

continental 

4.0E-1 lb/MWh 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 revised 

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 
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received 

d

 Based on best-performing similar source 

e

 Based on permit levels in comments received 

TABLE 2. PROPOSED 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 3.0E-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 revised 

a

 Based on best-performing similar source unless otherwise noted

b

 Based on DOE information 

7. Control Technologies to Meet Proposed New Source Emission 

Limits 

We have evaluated the levels of control that would 

generally be needed to meet the proposed emission limits for new 

sources and have compared those to the levels of control needed 
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to meet the new source emission limits in the final MATS rule. 

We compared the level of control needed by analyzing 

requirements for a new hypothetical 500 MW facility. The 

comparison led us to conclude that new EGUs would need to be 

designed to use the same types of emission control technologies 

to meet the proposed new source limits as would have been needed 

to meet the final MATS new source limits. More detailed 

discussion of this evaluation may be found in the memo “MATS 

Reconsideration: Control Technology Needed to Meet New Source 

Limits” contained in rulemaking docket EPA-HQ-OAR-2009-0234. 

Nothing in the statute requires the EPA to demonstrate that 

an existing source is able to meet all of the new source limits. 

Nevertheless, we note that based on our review of the data EPA 

collected as part of the 2010 ICR process, at least eight 

existing non-low rank virgin coal-fired EGUs and one low rank 

virgin coal-fired EGU have reported short-term stack test data 

that demonstrate that these EGUs have in practice achieved the 

new source limits proposed in this notice (considering all of 

their submitted data). Furthermore, for HCl (as well as the SO2

surrogate) and filterable PM, the new source limits proposed in 

this notice are consistent with those in several permits for 
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EGUs that have not yet commenced construction. For Hg, the new 

source limits proposed in this notice are consistent with the 

levels that a number of control vendors have suggested in their 

petitions for reconsideration are achievable and capable of 

being measured with an appropriate level of accuracy. 

8. Filterable PM Monitoring 

We provided several monitoring options for the filterable 

PM standard in the final rule, including quarterly stack 

testing, PM CEMS, and PM continuous parameter monitoring system 

(PM CPMS) with annual testing. For many reasons, including 

continued use of already-installed instruments on some EGUs, 

direct (as opposed to parametric) measurement of the pollutant 

of concern, and continuous feedback for process control, we 

believe that many EGU owners or operators will choose to use PM 

CEMS to monitor the proposed filterable PM limit. 

We solicit comment on whether to retain the quarterly stack 

testing compliance option, as this option may not be necessary 

because continuous, direct measurement of filterable PM or a 

correlated parameter is available and likely to be used by most 

sources to monitor compliance with the revised standard. With 

respect to the PM CPMS compliance option for new EGUs, we 
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considered three ways to establish an operating limit based on 

emissions testing. The first way would allow an EGU owner or 

operator to use the highest parameter value obtained during an 

individual emissions test when the result of that individual 

test was below the limit as the operating limit. The second way 

would allow an EGU owner or operator to use the average 

parameter value obtained from all runs pertaining to an 

individual emissions test as the operating limit. The third way, 

would allow an EGU owner or operator whose PM emissions as 

demonstrated during performance testing do not exceed 75 percent 

of the PM emissions limit to set his PM CPMS operating limit by 

linearly scaling the average operating value obtained during all 

the runs to be equivalent to the value at 75 percent of the 

limit; an EGU owner or operator whose PM emissions as 

demonstrated during performance testing exceed 75 percent of the 

PM emissions limit would establish his operating limit as a 30-

day rolling average equal to the average PM CPMS values recorded 

during performance testing. Such an approach would prevent 

unnecessary retests for EGUs with low PM emissions. 

Even though this rule proposes the third way, we solicit 

comments on the appropriateness of any of the three ways to 
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establish a PM CPMS operating limit for new EGUs. 

In addition, this rule proposes to require emissions 

testing after each exceedance of the operating limit for new 

sources. This rule proposes a number of consequences if the PM 

monitoring parameter is exceeded. First, the EGU owner or 

operator will have 48 hours to conduct an inspection of the 

control device(s) and to take action to restore the controls to 

proper operation, if necessary, and 45 days to conduct a Method 

5 compliance test under the same operating conditions to verify 

ongoing compliance with the filterable PM limit. Within 60 days, 

the EGU owner or operator will have to complete the emissions 

sampling, sample analyses, and verification that the EGU is in 

compliance with its emissions limit, as well as having to 

determine an operating limit based on the PM CPMS data collected 

during the performance test. The EGU owner or operator would 

then compare the recalculated operating limit with the existing 

operating limit and, as appropriate, adjust the numerical 

operating limit to reflect compliance performance. Adjustments 

could include applying the most recently established value or 

combining the data collected over multiple performance tests to 

establish a more representative value. The EGU owner or operator 
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would then apply the reverified or adjusted operating limit 

value from that time forward. 

Second, this rule proposes to limit the number of 

exceedances of the site-specific CPMS limit leading to follow-up 

performance tests in any 12 month process operating period and 

that an excess of this number be considered a violation of the 

standard. This presumption of violation could be rebutted by the 

EGU owner or operator, but would require more than a Method 5 

test as a basis for the rebuttal (e.g., results of physical 

inspections would also need to be included). This additional 

information is necessary since a Method 5 test could not be 

conducted during or immediately following the discovery of 

exceedances and would not necessarily represent conditions 

identical to those when the exceedances occurred. The basis for 

this part of the proposal is that the site-specific CPMS 

operating limit reflects a 30-day average that should represent 

an actual emissions level lower than the three test run 

numerical emissions limit since variability is mitigated over 

time. Consequently, we believe that there should be few, if any, 

exceedances from the 30-day parametric limit and there is a 

reasonable basis for presuming that exceedances that lead to 
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multiple performance tests to represent poor control device 

performance and to be a violation of the standard. Therefore, 

this rule proposes that PM CPMS exceedances leading to more than 

four required performance tests in a 12-month process operating 

period is presumed to be a violation of this standard, subject 

to an EGU owner or operator’s ability to rebut that presumption 

about process and control device operations in addition to the 

Method 5 performance test results. We solicit comment on this 

proposed revised approach.B. Eligibility to Be a New Source

The CAA section 112(a)(4) defines a new source as a 

stationary source “the construction or reconstruction of which 

is commenced after the Administrator first proposes regulations 

under this section establishing an emissions standard applicable 

to such source.” The EPA views the new source trigger date (the 

date EPA “first proposes regulations”) to be the date EPA first 

proposes standards under a particular rulemaking record. (74 FR 

21158). In this case, EPA first proposed standards for EGUs on 

May 3, 2011, and although we are proposing revisions to certain 

new source standards, the rulemaking record remains the same. As 

such, we are not proposing to revise the trigger date for 

determining whether a source is a new source. Any source which 
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commenced construction or reconstruction after May 3, 2011 is 

subject to the new source standards.6

Furthermore, it is the EPA’s technical judgment that new 

sources would need to adopt the same or similar emissions 

control strategies under the amended standards as they would 

have under the promulgated standards. The revised standards 

remain stringent and can be met, in our view, using the same or 

similar control strategies as would have been required to meet 

the standards in the final rule. 

C. Startup and Shutdown Provisions

The EPA received petitions asserting that the public lacked 

an opportunity to comment on the startup and shutdown provisions 

in the final MATS. Petitioners also assert that the definitions 

of “startup” and “shutdown” in the final MATS and the provisions 

for work practice standards did not adequately address 

applicability to certain types of units, fuels considered 

“clean,” and operational limitations for certain EGU types 

and/or pollution control devices. 

We proposed numerical standards for startup and shutdown 

 

6

 We are unaware of any new source that has commenced 

construction or reconstruction since May 3, 2011. 
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periods, and in response to comments on the proposed rule we 

changed those standards in the final MATS to work practice 

standards. Among other things, the work practice standards 

required sources to combust clean fuels during startup and 

shutdown periods and required sources to engage APCDs when coal 

or oil was fired in the EGU. (See 77 FR 9380-83). We also 

revised the definitions of “startup” and “shutdown” after 

considering comments we received. Although we revised these 

provisions in response to comments, we are granting 

reconsideration on this issue to provide an opportunity for 

comment on the final startup and shutdown standards and those we 

have revised and propose today. For further discussion of 

petitioners’ concerns and these proposed revisions, please refer 

to the memo “Startup and shutdown provisions” in rulemaking 

docket EPA-HQ-OAR-2009-0234. Below we summarize the startup and 

shutdown revisions proposed today. 

1. Definitions 

We are proposing to revise the definitions of startup and 

shutdown in this reconsideration notice as set forth in 40 CFR 

63.10042. Petitioners asserted that the final rule’s definitions 

of startup and shutdown were not sufficiently clear, should 
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accommodate operation of cogeneration units, and did not 

accurately reflect startup conditions for all affected units, 

particularly supercritical units. We have clarified the 

definitions and added provisions including useful thermal 

energy.7

 We believe that these changes address petitioners’ 

concerns. For more discussion, please refer to the memo “Startup 

and shutdown provisions” in rulemaking docket EPA-HQ-OAR-2009-

0234. 

2. Work Practice Standards 

We are proposing several revisions to the finalized work 

practice standards. Petitioners asserted that the final rule’s 

work practice standards should include certain additional fuels 

as “clean fuels” and recognize operating limitations of certain 

EGU types and APCDs. Specifically, petitioners contend that the 

list of clean fuels required for use during startup in order to 

minimize emissions should include synthetic natural gas, syngas, 

and ultra-low sulfur diesel (ULSD). The EPA has also been 

informed since the final rule that propane is used to startup 

some EGUs and has been requested to consider it as a clean fuel. 

Petitioners additionally contend that the standards need to 

 

7

 16 U.S.C. 796(18)(A) and 18 CFR 292.202(c).
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recognize operating conditions for FBC EGUs that inject 

limestone for acid gas control, selective non-catalytic 

reduction systems (SNCRs), selective catalytic reduction systems 

(SCRs), and other systems. 

In this reconsideration notice, we are proposing to add 

certain synthetic natural gas, syngas, propane, and ULSD to the 

list of clean fuels. We solicit comment on our understanding of 

clean fuels for startup and shutdown. 

We are also proposing to require EGU source owners and 

operators, when firing coal, solid oil-derived fuel, or residual 

oil in the EGU during startup or shutdown, to vent emissions to 

the main stack(s) and operate all control devices necessary to 

meet the operating standards that apply at all other times under 

the final rule (with the exception of limestone injection in FBC 

EGUs, dry scrubbers, SNCRs, and SCRs). Owners and operators of 

EGUs are responsible for starting limestone injection in FBC 

EGUs, dry scrubbers, SNCRs, and SCRs as expeditiously as 

possible, but, in any case, when necessary to comply with other 

standards applicable to the source that require operation of 

those control devices. 
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Additionally, we are proposing to revise the final rule’s 

work practice requirements to recognize constraints of certain 

EGUs and APCDs. The proposed revised standards allow limestone 

injection to start after appropriate temperatures have been 

attained in FBC EGUs that inject limestone for acid gas control 

and allow SNCR, SCR, and dry scrubber systems to start as soon 

as technically feasible after the appropriate temperature has 

been reached. 

For more discussion of each of these issues, please refer 

to the memo “Startup and shutdown provisions” in rulemaking 

docket EPA-HQ-OAR-2009-0234. 

3. Treatment of IGCC EGU syngas 

The EPA understands that at an IGCC EGU, syngas is 

generated in the gasifier and combusted in the turbine. During 

the startup and shutdown periods, some or all of the syngas 

produced may not be combusted in the turbine. We are proposing 

two options for IGCC EGUs for handling syngas not fired in the 

combustion turbine: (1) syngas must be flared, not vented or (2) 

syngas must be routed to duct burners, which may need to be 

installed, and the flue gas from the duct burners must be routed 

to the heat recovery steam generator. We are soliciting comments 
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on the need to flare the unfired syngas, if it is more 

appropriate to require routing of the unfired syngas back into 

the system for all IGCC EGUs, and on the costs of adding duct 

burners, should they be required. 

We solicit comments on the proposed revisions to the 

startup and shutdown requirements set forth in this notice. 

V. Discussion of Provisions Subject to Reconsideration – Utility 

NSPS 

Petitioners state that because the final Utility NSPS rule 

contains a definition of “natural gas” that was not included in 

the proposed rule, they were not able to comment on the 

definition. Further, petitioners maintain that the definition 

established in the final rule is not a “logical outgrowth” of 

the proposed rule. Although the definition was changed between 

proposal and final based on public comment, we are re-proposing 

the definition of natural gas that was in the final Utility NSPS 

to allow additional opportunity to comment. 

We are also proposing several additional amendments so that 

synthetic natural gas will receive similar treatment as natural 

gas. We seek comment on all aspects of these additional 

amendments. First, consistent with the NESHAP definition, we are 
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proposing to clarify the definition of coal to include synthetic 

natural gas derived from coal. As such, we are also proposing to 

add synthetic natural gas to the opacity exemption in paragraph 

40 CFR 60.42Da(b)(2) since facilities burning synthetic natural 

gas would otherwise be subject to an opacity standard. In 

addition, we are also proposing to replace “natural gas” with 

“gaseous fuels” in 40 CFR 60.49Da(b) so facilities burning 

desulfurized coal-derived synthetic natural gas are not required 

to install an SO2 CEMS. The proposed amendments to the startup 

and shutdown requirements in the NESHAP portion of this proposal 

would also allow the use of synthetic natural gas for the work 

practice standards required for PM emissions control during 

periods of startup and shutdown. 

Additional proposed amendments include amending the 

definition of an IGCC to be similar to the corresponding NESHAP 

MATS definition. Potential language is as follows: 

Integrated gasification combined cycle electric utility 

steam generating unit or IGCC electric utility steam 

generating unit means an electric utility combined cycle 

gas turbine that burns a synthetic gas derived from coal 

and/or solid oil-derived fuel for more than 10.0 percent of 

the average annual heat input during any 3 consecutive 

calendar years or for more than 15.0 percent of the annual 

heat input during any one calendar year in a combined-cycle 

gas turbine. No solid coal or solid oil-derived fuel is 
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directly burned in the unit during operation. 

We believe that this would address the issue of IGCC 

facilities switching applicability between the stationary 

combustion turbine NSPS (40 CFR Part 60, subpart KKKK) and the 

Utility NSPS. However, we are specifically requesting comment if 

it would be more appropriate to maintain the existing NSPS IGCC 

definition and add “startup and commissioning, shutdown” as 

suggested by one petitioner. Potential language for the 

alternate definition is as follows: 

Integrated gasification combined cycle electric utility 

steam 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. 

In addition, the rationale for the filterable PM standard 

startup and shutdown work practice provision discussed in the 

NESHAP portion of this notice also applies to the filterable PM 

startup and shutdown standards in the Utility NSPS. Therefore, 

we are proposing to amend both the emissions rate calculation 

procedure and monitoring requirements for PM to be similar to 
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the requirements specified in the NESHAP for new facilities. 

Owners/operators of EGUs subject to the Utility NSPS would 

calculate the filterable PM emissions rate as the average of the 

measured hourly rates during the applicable averaging period 

(instead of as the sum of the emissions divided by the sum of 

the output over the applicable averaging period) and would use 

either a PM CEMS, PM CPMS, or quarterly performance testing to 

demonstrate compliance with the applicable standard.8

Finally, we are proposing to clarify that owners/operators 

electing to use PM CPMS to monitor PM emissions are exempt from 

the requirement to install a continuous opacity monitoring 

system (COMS) and would be allowed to elect to use alternate 

opacity monitoring procedures currently allowed in the Utility 

NSPS. 

VI. Technical Corrections and Clarifications 

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

corrections notice addressing certain corrections to the 

 

8

 As discussed in the final Utility NSPS Response to Comments 

document, because the amended NOX and SO2 standards used CEMS 

data and included all periods of operation when establishing the 

numerical values for those standards, we are not proposing to 

amend how periods of startup and shutdown are handled or how the 

emission rates are calculated for the Utility NSPS NOX and SO2

standards. See docket entry EPA-HQ-OAR-2011-0044-5759, p. 7.
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February 16, 2012 (77 FR 9304) MATS. 

In this notice, we are proposing several additional 

technical corrections. These amendments are being proposed to 

correct inaccuracies and other inadvertent errors in the final 

rule and to make the rule language consistent with provisions 

addressed through this reconsideration. We are soliciting 

comment only on whether the proposed changes provide the 

intended accuracy, clarity and consistency. These proposed 

technical changes are described in tables 3 and 4 of this 

preamble. We request comment on all of these proposed changes. 

TABLE 3. MISCELLANEOUS PROPOSED TECHNICAL CORRECTIONS TO 40 CFR 

PART 60, SUBPART Da 

Section of subpart Da Description of proposed 

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 
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TABLE 4. MISCELLANEOUS PROPOSED TECHNICAL CORRECTIONS TO 40 CFR 

PART 63, SUBPART UUUUU 

Section of subpart UUUUU Description of proposed 

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 

“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 63.10011(g) Clarify the language to use the 

word “and” instead of “or” 

between the words “startup” and 

“shutdown.” 
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Clarify the language to use the 

word “or” instead of “and” 

between the words “oil-fired” 

and “solid.” 

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 Revise the definition of “boiler 

operating day” to clarify that 

periods of startup or shutdown 

are not included. 

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 

“<.” 

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. 

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).” 
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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 Proposed Rule

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 rule will result in no 

significant change in costs, emission reductions, or benefits.9

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

changes would likely be small relative to both the overall costs 

 

9

 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 the memo “Economic Impact Analysis for the 

Proposed 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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of the individual projects and the overall costs and benefits of 

the final rule, which is dominated by actions taken by existing 

units. Further, as noted elsewhere in this preamble, we believe 

that EGUs would put on the same controls for this proposed rule 

that they would have for the original final, so there should not 

be any incremental costs related to this proposed revision. 

A. What are the air impacts? 

We believe that electric power companies will install the 

same or similar control technologies to comply with the revised 

standards proposed in this action as they would have installed 

to comply with the previously finalized standards. Accordingly, 

we believe that this proposed rule will not result in 

significant changes in emissions of any of the regulated 

pollutants. 

B. What are the energy impacts? 

This proposed rule is not anticipated to have an effect on 

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 standards. 

C. What are the compliance costs? 
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We believe there will be no significant change in 

compliance costs as a result of this proposed rule because 

electric power companies would install the same or similar 

control technologies as they would have installed to comply with 

the previously finalized standards. Moreover, we find no 

additional monitoring costs are necessary to comply with the 

proposed rule; however, as in any other rule, EGU owners or 

operators may choose to conduct additional monitoring (and incur 

its expense) for their own purposes. 

D. 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 proposed in this action as they would have chosen to 

comply with the previously finalized standards, we do not 

anticipate that this proposed rule will result in significant 

changes in emissions, energy impacts, costs, benefits, or 

economic impacts. Likewise, we believe this rule will not have 

any impacts on the price of electricity, employment or labor 

markets, or the U.S. economy. 

E. What are the benefits of the proposed standards? 

As previously stated, the EPA anticipates the power sector 
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will not incur significant compliance costs or savings as a 

result of this proposal and we do not anticipate any significant 

emission changes resulting from this rule. Therefore, there are 

no direct monetized benefits or disbenefits associated with this 

proposed rule.

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 arising out of legal 

mandates.” 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. 

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 Proposed 

Reconsideration of the Mercury and Air Toxics Standards” found 
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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 standard, we project that this rule 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 notice of reconsideration 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 77FR 

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. 

C. Regulatory Flexibility Act

The Regulatory Flexibility Act generally requires an agency 

to prepare a regulatory flexibility analysis of any rule subject 
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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 notice of 

reconsideration 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-for-profit 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 

Utilities-Fossil Fuel Electric Power Generation, a firm is small 

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

reconsideration 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 notice of 

reconsideration imposes no additional regulatory requirements on 

owners or operators of affected sources. We have therefore 

concluded that today’s notice of reconsideration will not result 

in a significant economic impact on a substantial number of 

small entities. We continue to be interested in the potential 

impacts of the rule on small entities and welcome comments on 

issues related to such impacts. 

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

the private sector. Therefore, this action is not subject to the 

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. 

In the spirit of EO 13132, and consistent with EPA policy 

to promote communications between EPA and state and local 
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governments, EPA specifically solicits comment on this notice of 

reconsideration from state and local officials. 

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, 

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 notice of 

reconsideration. The EPA specifically solicits comment on this 

notice of reconsideration from tribal officials. 

G. Executive Order 13045: Protection of Children from 

Environmental Health 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 Mercury and Air Toxics Standards on 

children. The results of the evaluation are discussed in that 

final rule (77 FR 9304; February 16, 2012) and are contained in 
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rulemaking docket EPA-HQ-OAR-2009-0234. 

The public is invited to submit comments or identify peerreviewed studies and data that assess effects of early life 

exposure to hazardous air pollutants. 

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 notice of reconsideration 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. 

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 
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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 rule, 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 rule (77 FR 

9441; February 16, 2012). Today’s notice of reconsideration does 

not propose the use of any additional technical standards beyond 

those cited in the final rule. Therefore, EPA is not considering 

the use of any additional voluntary consensus standards for this 

notice. 

The EPA welcomes comments on this aspect of this notice of 

reconsideration and, specifically, invites the public to 

identify potentially-applicable voluntary consensus standards 

and to explain why such standards should be used in this 
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regulation. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-income 

Populations

Executive Order 12898 (59 FR 7629 (Feb. 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 notice of reconsideration 

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 rule will result in 

no significant change in emission reductions. 

 
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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: _____ __, 201_. 

_______________________ 

Lisa P. Jackson, 

Administrator.
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For the reasons discussed in the preamble, the EPA proposes to 

amend 40 CFR parts 60 and 63 to read as follows: 

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES 

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

follows: 

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

2. 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. 

* * * * * 
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Integrated gasification combined cycle electric utility steam 

generating unit or IGCC electric utility steam generating unit

means an electric utility combined cycle gas turbine that burns 

a synthetic natural gas derived from coal and/or solid oilderived fuel for more than 10.0 percent of the average annual 

heat input during any 3 consecutive calendar years or for more 

than 15.0 percent of the annual heat input during any one 

calendar year in a combined-cycle gas turbine. No solid coal or 

solid oil-derived 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 
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any gaseous fuel produced in a process which might result in 

highly variable sulfur content or heating value. 

* * * * * 

3. Amend § 60.42Da by revising paragraphs (a), (b)(2), (e)(1) 

introductory text, and (e)(1)(ii) 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. 

* * * * * 
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(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 cause to be 

discharged into the atmosphere from that affected facility any 

gases that contain PM in excess of the applicable emissions 

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

* * * * * 

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

gases that contain PM in excess of the emission limits specified 

in paragraphs (c) or (d) of this section. 

* * * * * 

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

(a) For affected facilities for which construction, 

modification, or reconstruction commenced before May 4, 2011, 

the applicable PM emissions limit and opacity standard under 

§60.42Da, SO2 emissions limit under §60.43Da, and NOX emissions 

limit under §60.44Da apply at all times except during periods of 
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startup, shutdown, or malfunction. For affected facilities for 

which construction, modification, or reconstruction commenced 

after May 3, 2011, the applicable SO2 emissions limit under 

§60.43Da, NOX emissions limit under §60.44Da, and NOX plus CO 

emissions limit under §60.45Da apply at all times. The 

applicable PM emissions limit and opacity standard under 

§60.42Da apply at all times except during periods of startup and 

shutdown; however, you are required to meet the work practice 

requirements as specified in 60.42Da(e)(2) of this subpart 

during periods of startup and shutdown. 

* * * * * 

(f) For affected facilities for which construction, 

modification, or reconstruction commenced before May 4, 2011, 

compliance with the applicable daily average PM emissions limit 

is determined by calculating the arithmetic average of all 

hourly emission rates each boiler operating day, except for data 

obtained during startup, shutdown, or malfunction periods. Daily 

averages are only calculated for boiler operating days that have 

non-out-of-control data for at least 18 hours of unit operation 

during which the standard applies. Instead, all of the non-outof-control hourly emission rates of the operating day(s) not 
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meeting the minimum 18 hours non-out-of-control data daily 

average requirement are averaged with all of the non-out-ofcontrol hourly emission rates of the next boiler operating day 

with 18 hours or more of non-out-of-control PM CEMS data to 

determine compliance. For affected facilities for which 

construction, modification, or reconstruction commenced after 

May 3, 2011, compliance with the applicable 30-boiler operating 

day rolling average PM emissions limit is determined 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 shall 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. 

* * * * * 
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(3) As an alternative to complying with the requirements of 

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

to monitor the performance of an electrostatic precipitator 

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

in §60.42Da 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. 
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* * * * * 

5. Amend § 60.49Da by: 

a. Revising paragraphs (a) introductory text and (a)(2); 

b. Adding paragraphs (a)(2)(v) and (a)(3)iv); and 

c. Revising paragraphs (a)(4) introductory text, (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 shall 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. 

* * * * * 

(2) As an alternative to the monitoring requirements in 

paragraph (a)(1) of this section, an owner or operator of an 

affected facility that meets the conditions in either paragraph 

(a)(2)(i), (ii), (iii), (iv), or (v) of this section may elect 

to monitor opacity as specified in paragraph (a)(3) of this 

section. 

* * * * * 
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(v) 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. 

* * * * * 

(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 

shall 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 

“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 
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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 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 sitespecific monitoring plan approved by the permitting authority. 

This monitoring plan must include procedures and criteria for 

establishing and monitoring specific parameters for the affected 

facility indicative of compliance with the opacity standard. For 

testing performed as part of this site-specific monitoring plan, 

the permitting authority may require as an alternative to the 

notification and reporting requirements specified in §§60.8 and 

60.11 that the owner or operator submit any exceedances with the 

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

* * * * * 

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

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

measuring PM emissions according to the requirements of 

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

maintain a PM CPMS according to the requirements for new 

facilities specified in subpart UUUUU of part 63 of this 

chapter, or conduct quarterly testing according to the 

requirements for new 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. 

* * * * * 
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6. Amend § 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 turbines that does not meet the definition of an IGCC shall 

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 

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

as follows: 

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

8. Revise § 63.9982 in paragraphs (a) introductory text, (b), 

and (c) to read as follows: 

§ 63.9982 What is the affected source of this subpart? 
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* * * * * 

(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, or if you commence reconstruction 

after May 3, 2011. 

* * * * * 

9. Revise § 63.10005 in paragraphs (d)(2)(ii), (i)(4)(ii), and 

(i)(5) and add paragraph (i)(6) to 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 
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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 

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

* * * * * 

10. Revise § 63.10006 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-, and coal-fired EGUs and IGCC EGUs, 

you must conduct all applicable periodic emissions tests for 

filterable PM, or individual or total HAP metals emissions 

according to Table 5 to this subpart, §63.10007, and 

§63.10000(c), except as otherwise provided in §63.10021(d)(1). 

* * * * * 

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

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

performance tests? 

* * * * * 

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

limit and demonstrate continuous performance using a PM CPMS for 
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an applicable emission limit 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. 

* * * * * 

12. Revise § 63.10009 in paragraphs (b)(2) and (b)(3) to read as 

follows: 

§ 63.10009 May I use emissions averaging to comply with this 

subpart? 

* * * * * 

(b) * * * 

(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. 

ܹܧܣܴ ൌ ∑ ሾ∑ ሺܪ݁ݎ ௜ൈ ܴ݉௜ሻ ௡

௜ୀଵ ሿ௣

௣

௜ୀଵ ൅ ∑ ሺܶ݁ݎ ௜ൈ ܴݐ௜ሻ ௠

௜ୀଵ

∑ ሾ∑ ሺܴ݉௜ሻ ௡

௜ୀଵ ሿ௣

௣

௠ ௜ݐܴ ∑ ൅ ୀଵ௜

௜ୀଵ

 ሺݍܧ. 2ܽሻ

 
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Where: 

Heri = hourly emission rate (e.g., lb/MMBtu, lb/MWh) from unit 

i’s CEMS for the preceding 30-group boiler operating days, 

Rmi = hourly heat input or gross 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. 

* * * * * 

(3) Weighted 90-boiler operating day rolling average emissions 

rate equations for Hg emissions from EGUs in the “coal-fired 

unit not low rank virgin coal” subcategory. Use equation 3a or 

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

ܹܧܣܴ ൌ ∑ ሾ∑ ሺܪ݁ݎ ௜ൈ ܴ݉௜ሻ ௡

௜ୀଵ ሿ௣

௣

௜ୀଵ ൅ ∑ ሺܶ݁ݎ ௜ൈ ܴݐ௜ሻ ௠

௜ୀଵ

∑ ሾ∑ ሺܴ݉௜ሻ ௡

௜ୀଵ ሿ௣

௣

௠ ௜ݐܴ ∑ ൅ ୀଵ௜

௜ୀଵ

 ሺݍܧ. 3ܽሻ

 

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, 
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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. 

* * * * * 

13. Revise § 63.10010 paragraph (j)(1)(i) to read as follows: 

§ 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. 

* * * * * 

14. Revise § 63.10011 in paragraphs (f) and (g) to read as 
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follows: 

§ 63.10011 How do I demonstrate initial compliance with the 

emissions limits and work practice standards? 

* * * * * 

(f) You must use during periods of startup or shutdown any one 

or combination of the following clean fuels: natural gas, 

synthetic natural gas, propane, distillate oil, synthesis gas 

(syngas), and ultra-low sulfur diesel (ULSD). 

* * * * * 

(g) You must follow the startup and shutdown requirements in 

Table 3 for each coal-fired, liquid oil-fired, or solid oilderived fuel-fired EGU. 

* * * * * 

15. Revise § 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 
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average value from the established operating parameter limit for 

an EGU subject to the emissions limits in Table 1 to this 

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 from 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 
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of this subpart. 

* * * * * 

16. Revise § 63.10023 paragraph (b) to read as follows: 

§ 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. 
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(A) Determine your 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 established 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. 
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ݔ ൌ భ

೙ ∑ ܺଵ ௡

௜ୀଵ , ݕ ൌ భ

೙ ∑ ܻଵ ௡

௜ୀଵ (Eq. 10) 

Where: 

X1 = the PM CPMS data points for the runs constituting the 

performance test, 

Y1 = the PM emissions value (in lb/MWh) for the runs constituting 

the performance test, and 

n = the number of data points. 

(C) With your instrument zero expressed in milliamps, your test 

average PM CPMS milliamp value, and your test average PM 

emissions value (in lb/MWh) from your compliance runs, determine 

a relationship of PM lb/MWh per milliamp with equation 11. 

  X z

Y

 

1

1 R (Eq. 11) 

Where: 

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

Y1 = the three run average PM lb/MWh, 

X1 = the three run average milliamp output from you PM CPMS, and 

z = the milliamp equivalent of your instrument zero determined 

from (i)(A). 

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

operating limit using the PM lb/MWh per milliamp value from 
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equation 11 in equation 12, below. This sets your operating 

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

your emission limit. 

Ol = z + (0.75(L))/ R (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 (i)(A), 

and 

R = the relative lb/ton-clinker 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 

equation 13. 
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ܱ௛ ൌ భ

೙ ∑ ܺଵ ௡

௜ୀଵ (Eq. 13) 

Where: 

X1 = 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 

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 
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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. Revise § 63.10030 in 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 

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

that is an affected source. 
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(d) When you are required to conduct a performance test, you 

must submit a Notification of Intent to conduct a performance 

test at least 60 days before the performance test is scheduled 

to begin. 

* * * * * 

18. Amend § 63.10042 by: 

a. Revising in alphabetical order the definitions of “Boiler 

operating day,” “Shutdown”, “Startup”, and “Unit designed for 

coal > 8,300 Btu/lb subcategory”; and 

b. Adding a new definition of “Clean fuel”. 

The revised and added text reads as follows: 

§ 63.10042 What definitions apply to this subpart? 

* * * * * 

Boiler operating day means a 24-hour period that begins at 

midnight and ends the following midnight during which any fuel 

is combusted at any time in the EGU, excluding periods of 

startup or shutdown. It is not necessary for the fuel to be 

combusted the entire 24-hour period. 

* * * * * 

Clean fuel means natural gas, synthetic natural gas that meets 

the specification necessary for that gas to be transported on a 
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Federal Energy Regulatory Commission (FERC) regulated pipeline, 

propane, distillate oil, synthesis gas (syngas), or ultra-lowsulfur diesel (ULSD). 

* * * * * 

Shutdown means the period in which cessation of operation of an 

EGU is initiated for any purpose. Shutdown begins when the EGU 

no longer generates electricity or makes useful thermal energy 

(such as heat or steam) for industrial, commercial, heating, or 

cooling purposes or when no coal, liquid oil, syngas, or solid 

oil-derived fuel is being fired in the EGU, whichever is 

earlier. Shutdown ends when the EGU no longer generates 

electricity or makes useful thermal energy (such as steam or 

heat) for industrial, commercial, heating, or cooling purposes, 

and no fuel is being fired in the EGU. 

Startup means the period in which operation of an EGU is 

initiated for any purpose. Startup begins with either the firstever firing of fuel in an EGU for the purpose of producing 

electricity or useful thermal energy (such as heat or steam) for 

industrial, commercial, heating, or cooling purposes or the 

firing of fuel in an EGU for any purpose after a shutdown event. 

Startup ends when the EGU generates electricity that is sold or 
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used for any other purpose (including on site use), or the EGU 

makes useful thermal energy (such as heat or steam) for 

industrial, commercial, heating, or cooling purposes (16 U.S.C. 

796(18)(A) and 18 CFR 292.202(c)), whichever is earlier. 

* * * * * 

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. Amend the Appendix by revising Table 1 to Subpart UUUUU of 

Part 63 to read as follows: 

Table 1 to Subpart UUUUU of Part 63 — Emission Limits for New or 

Reconstructed EGUs 

As stated in §63.9991, you must comply with the following 

applicable emission limits: 

If your EGU 

is in this 

subcategory 

... 

For the following 

pollutants ... 

You must meet the 

following emission 

limits and work 

practice standards 

... 

Using these 

requirements, 

as appropriate 

(e.g., 

specified 

sampling 

volume or test 

run duration) 

and 

limitations 

with the test 

methods in 
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Page 98 of 110 

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. 

 * * * * * * * 

 Individual HAP 

metals: 

 

 

 

 

 

 

 

 

 

 

Collect a 

minimum of 3 

dscm per run. 

 * * * * * * * 

 Lead (Pb) 3.0E-2 lb/GWh 

 * * * * * * * 

 Selenium (Se) 5.0E-2 lb/GWh 

 b. Hydrogen 

chloride (HCl) 

 1.0E-2 lb/MWh For Method 

26A, collect a 

minimum of 3 

dscm per run. 

For ASTM 

D6348-032

 or 

Method 320, 

sample for a 

minimum of 1 

hour. 

 OR 

 Sulfur dioxide 

(SO2)3 

 1.0 lb/MWh SO2 CEMS. 
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Page 99 of 110 

 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. 

 * * * * * * * 

 Individual HAP 

metals: 

Collect a 

minimum of 3 

dscm per run. 

 * * * * * * * 

 Lead (Pb) 3.0E-2 lb/GWh 

 * * * * * * * 

 Selenium (Se) 5.0E-2 lb/GWh 

 b. Hydrogen 

chloride (HCl) 

 1.0E-2 lb/MWh For Method 

26A, collect a 

minimum of 3 

dscm per run. 

For ASTM 

D6348-032 or 

Method 320, 

sample for a 

minimum of 1 

hour. 

 OR 

 Sulfur dioxide 

(SO2)3 

 1.0 lb/MWh SO2 CEMS. 

 * * * * * * * 

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 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release 

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 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 

 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. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release 

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Page 101 of 110 

4. Liquid 

oil-fired 

unit – 

continental 

(excluding 

limited-use 

liquid oilfired 

subcategory 

units). 

 

 

a. Filterable 

particulate 

matter (PM) 

 4.0E-1 lb/MWh1 Collect a 

minimum of 1 

dscm per run. 

 * * * * * * * 

6. Solid oilderived fuelfired unit. 

 

 

a. Filterable 

particulate 

matter (PM) 

 3.0E-2 lb/MWh1 Collect a 

minimum of 1 

dscm per run. 

 * * * * * * * 

 Sulfur dioxide 

(SO2)3 

 1.0 lb/MWh SO2 CEMS. 

 * * * * * * * 

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 and SO2 CEMS installed and 

operating. 

4

 Duct burners on syngas; gross electric output. 

5

 Duct burners on natural gas; gross electric output 

* * * * * 

20. Amend the Appendix by revising Table 3 to Subpart UUUUU of 

Part 63 to read as follows: 

Table 3 to Subpart UUUUU of Part 63 — Work Practice Standards

As stated in §§63.9991, you must comply with the following 

applicable work practice standards: 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release 

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Page 102 of 110 

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

1. An existing EGU Conduct a tune-up of the EGU burner 

and combustion controls at least each 

36 calendar months, or each 48 

calendar months if neural network 

combustion optimization software is 

employed, as specified in 

§63.10021(e).

2. A new or 

reconstructed EGU 

Conduct a tune-up of the EGU burner 

and combustion controls at least each 

36 calendar months, or each 48 

calendar months if neural network 

combustion optimization software is 

employed, as specified in 

§63.10021(e).

3. A coal-fired, 

liquid oil-fired, or 

solid oil-derived 

fuel-fired EGU 

during startup 

You must operate all CMS during 

startup. 

For startup of an EGU, you must use 

one or a combination of the following 

clean fuels: natural gas, synthetic 

natural gas, propane, distillate oil, 

syngas, and ultra-low sulfur diesel. 

Once you start firing coal, residual 

oil, or solid oil-derived fuel, you 

must vent emissions to the main 

stack(s) and engage all of the 

applicable control devices except 

limestone injection in FBC EGUs, dry 

scrubber, SNCR, and SCR. You must 

start your limestone injection in FBC 

EGUs, dry scrubber, SNCR, and SCR 

systems as expeditiously as possible, 

but, in any case, when necessary to 

comply with other standards applicable 

to the source that require operation 

of the control devices. 

Relative to the syngas not fired in 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release 

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Page 103 of 110 

the combustion turbine of an IGCC EGU 

during startup, you must either: (1) 

flare the syngas or (2) route the 

syngas to duct burners, which may need 

to be installed, and route the flue 

gas from the duct burners to the heat 

recovery steam generator. 

You must comply with all applicable 

emission limits at all times except 

for startup or shutdown periods 

conforming with this work practice. 

You must collect monitoring data 

during periods of startup, as 

specified in §63.10020(a). You must 

keep records during periods of 

startup. You must provide reports 

concerning activities and periods of 

startup, as specified in §63.10011(g) 

and §63.10021(h) and (i). 

4. A coal-fired, 

liquid oil-fired, or 

solid oil-derived 

fuel-fired EGU 

during shutdown 

You must operate all CMS during 

shutdown. 

While firing coal, residual oil, or 

solid oil-derived fuel during 

shutdown, you must vent emissions to 

the main stack(s) and operate all 

applicable control devices, except 

limestone injection in FBC EGUs, dry 

scrubber, SNCR, and SCR. You must 

operate your limestone injection in 

FBC EGUs, dry scrubber, SNCR, and SCR 

systems as expeditiously as possible, 

but, in any case, when necessary to 

comply with other standards that apply 

to the source and that require 

operation of the control devices. 

If, in addition to the fuel used prior 

to initiation of shutdown, another 

fuel must be used to support the 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release 

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Page 104 of 110 

shutdown process, that additional fuel 

must be one or a combination of the 

following clean fuels: natural gas, 

synthetic natural gas, propane, 

distillate oil, syngas, and ultra-low 

sulfur diesel. 

Relative to the syngas not fired in 

the combustion turbine of an IGCC EGU 

during shutdown, you must either: (1) 

flare the syngas or (2) route the 

syngas to duct burners, which may need 

to be installed, and route the flue 

gas from the duct burners to the heat 

recovery steam generator. 

You must comply with all applicable 

emission limits at all times except 

during startup and shutdown periods at 

which time you must meet this work 

practice. You must collect monitoring 

data during periods of startup, as 

specified in §63.10020(a). You must 

keep records during periods of 

startup. You must provide reports 

concerning activities and periods of 

startup, as specified in §63.10011(g) 

and §63.10021(h) and (i). 

* * * * * 

21. Amend the Appendix by revising Table 4 to Subpart UUUUU of 

Part 63 to read as follows: 

Table 4 to Subpart UUUUU of Part 63 — Operating Limits for EGUs 

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

operating limits: 

If you demonstrate You must meet these operating 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release 

During Review *** 

Page 105 of 110 

compliance using... 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). 

22. Amend the Appendix by revising 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: 

(1) The test plan preparation and implementation in the Annexes 

to ASTM D6348–03, Sections A1 through A8 are mandatory; (2) For 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release 

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Page 106 of 110 

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: 

* * * * * 

23. Amend the Appendix by revising 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, 

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 

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 

highest 1-hour 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release 

During Review *** 

Page 107 of 110 

total HAP 

metals, or 

individual 

HAP metals 

for an 

existing 

EGU. 

 

 

signal). 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)fr

om data obtained 

during the 

performance 

testdemonstrating 

compliance with 

the filterable PM 

or HAP metals 

emissions 

limitations. 

24. Amend the Appendix by revising Table 7 to Subpart UUUUU of 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release 

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Page 108 of 110 

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 arithmetic 30-(or 

90-) boiler operating day rolling 

average of all of the quality 

assured hourly average PM CPMS 

output data (e.g., milliamps, PM 

concentration, raw data signal) 

collected for all operating hours 

for the previous 30 boiler 

operating days, excluding data 

recorded during periods of startup 

or shutdown. 

3. Site-specific monitoring 

using CMS for liquid oilfired EGUs for HCl and HF 

If applicable, by conducting the 

monitoring in accordance with an 

approved site-specific monitoring 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release 

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Page 109 of 110 

emission limit 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 applicable emissions 

limit in Table 1 or 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 oilfired, or solid oil-derived 

fuel-fired EGUs during 

startup 

Operating in accordance with Table 

3. 

7. Work practice standards 

for coal-fired, liquid oilfired, or solid oil-derived 

fuel-fired EGUs during 

shutdown 

Operating in accordance with Table 

3. 

25. Amend the Appendix by revising 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 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release 

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Page 110 of 110 

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 shall apply to the annual RATAs of the sorbent 

trap monitoring system. 

* * * * * 

26. Amend the Appendix by revising section 3.1.2.1.3 and the 

title to section 5.3.4 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 

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

* * * * * 

5.3.3 Conditional Data Validation 

* * * * *