Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 71323 

* * * * * 

Issued in Washington, DC, this 20th day of 

November, 2012. 

Laricke Blanchard, 

Deputy Director for Policy, Pension Benefit 

Guaranty Corporation. 

[FR Doc. 2012–28892 Filed 11–29–12; 8:45 am] 

BILLING CODE 7709–01–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 Coaland Oil-Fired Electric Utility Steam 

Generating Units and Standards of 

Performance for Fossil-Fuel-Fired 

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

Generating Units 

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 titled ‘‘National Emission 

Standards for Hazardous Air Pollutants 

from Coal- and Oil-fired Electric Utility 

Steam Generating Units and Standards 

of Performance for Fossil-Fuel-Fired 

Electric Utility, Industrial-CommercialInstitutional, and Small IndustrialCommercial-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 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 December 31, 

2012. 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 December 10, 2012 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. EPA–HQ– 

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. 

• Email: Comments may be sent by 

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

OAR–2011–0044 (NSPS action) or EPA– 

HQ–OAR–2009–0234 (NESHAP/MATS 

action). 

• Fax: Fax your comments to: (202) 

566–9744, Docket ID No. EPA–HQ– 

OAR–2011–0044 (NSPS action) or 

Docket ID No. EPA–HQ–OAR–2009– 

0234 (NESHAP/MATS action). 

• Mail: Send your comments on the 

NESHAP/MATS action to: EPA Docket 

Center (EPA/DC), Environmental 

Protection Agency, Mailcode: 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 

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 email. The 

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

an ‘‘anonymous access’’ system, which 

means the EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to the EPA without 

going through http:// 

www.regulations.gov, your email 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, the EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If the EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, the EPA may not 

be able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. 

Public Hearing. If anyone contacts 

EPA by December 10, 2012 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 


wreier-aviles on DSK5TPTVN1PROD with 
71324 Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 

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 rule 

by December 10, 2012, 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. 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; 

Email address: maxwell.bill@epa.gov. 

For the NSPS action: Mr. Christian 

Fellner, Energy Strategies Group, Sector 

Policies and Programs Division, (D243– 

01), Office of Air Quality Planning and 

Standards, U.S. Environmental 

Protection Agency, Research Triangle 

Park, North Carolina 27711; Telephone 

number: (919) 541–4003; Fax number 

(919) 541–5450; Email address: 

fellner.christian@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Outline. The information presented in 

this preamble is organized as follows: 

I. General Information 

A. Does this 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 

Risks and Safety Risks 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

I. General Information 

A. Does this reconsideration notice 

apply to me? 

Categories and entities potentially 

affected by today’s notice include: 

Category NAICS code 1 Examples of potentially regulated entities 

Industry ..................................... 221112 Fossil fuel-fired electric utility steam generating units. 

Federal government ................. 2 221122 Fossil fuel-fired electric utility steam generating units owned by the Federal government. 

State/local/Tribal government ... 2 221122 Fossil fuel-fired electric utility steam generating units owned by municipalities. 

921150 Fossil fuel-fired electric utility steam generating units in Indian country. 

1 North American Industry Classification System. 

2Federal, 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 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 email. 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 


wreier-aviles on DSK5TPTVN1PROD with 
Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 71325 

1The recent decision by the U.S. Court of 

Appeals for the D.C. Circuit regarding the Cross 

State Air Pollution Rule (CSAPR) has no impact on 

the issues being reconsidered in this action. 

2Because, 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. 

3CAA section 112(d)(2) requires the EPA to 

consider whether more stringent beyond-the-floor 

standards should be established. 

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. 

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 

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

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 fuel-fired EGUs. 

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 oilderived fuel-fired 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. We solicit comment on the 

revised standards. Additional details on 

the proposed emission limits 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 

Coal- and Oil-fired Electric Utility 

Steam Generating Units, Proposed Rule’’ 

in rulemaking docket EPA–HQ–OAR– 

2009–0234. 

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–HQ–OAR–2009–0234; ‘‘MATS 

Reconsideration: Beyond-the-Floor 

Memorandum’’ available 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 beyond-the-floor 

standard is appropriate.3 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 coal-fired 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 

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-CommercialInstitutional 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 reVerDate Mar<15>2010 14:04 Nov 29, 2012 Jkt 229001 PO 00000 Frm 00039 Fmt 4700 Sfmt 4700 E:\FR\FM\30NOR1.SGM 30NOR1

wreier-aviles on DSK5TPTVN1PROD with 
71326 Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 

examined 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 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 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 nonlow rank virgin coal subcategory is 

measurable using a sorbent trap 

monitoring system. 

As noted, however, petitioners have 

indicated that the long 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. 

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 

‘‘Determination of Representative 

Detection Level (RDL) and 3 X RDL 

Values for Mercury Measured Using 

Sorbent Trap Technologies’’ in 

rulemaking docket EPA–HQ–OAR– 

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 

UPL-calculated 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 reasonable, shorter 

sampling conditions—30-minute 

samples obtained at a sampling rate of 

0.5 liter per minute—the 

UPL-determined 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 (mg/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 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. 


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Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 71327 

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 

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-thefloor 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 

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-thefloor 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: Beyondthe-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 costeffective manner. Comments should 

include information on emissions, 

pollutant control efficiencies, 

operational reliability, current 

demonstrated applications, and costs. 

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 

design a secondary downstream 

‘‘polishing’’ PM control device. Such a 

device would add considerable cost to 

the project, and the incremental costeffectiveness would not be reasonable. 

See ‘‘MATS Reconsideration: Beyondthe-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 coal-fired 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’’ 

control device would result in costeffective 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–OAR–2009–0234. 

d. Beyond-the-floor analysis for PM 

from solid oil-derived fuel-fired 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 costeffectiveness would not be reasonable. 

e. Beyond-the-floor analysis for SO2

from solid oil-derived fuel-fired EGUs. 

The best performing source for SO2

emissions from solid oil-derived fuelfired 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 

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 


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4New 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 (see http://cfpub.epa.gov/RBLC/). 

5Note 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. 

6Tables 1 and 2 in this preamble set forth the new 

source limits the Agency is proposing to revise. 

However, to comply with Federal Register 

guidelines, ‘‘Table 1 to Subpart UUUUU of Part 

63—Emission Limits for New or Reconstructed 

EGUs’’ in the regulatory text includes all of the new 

source limits, including the limits that are not 

proposed to be revised and are not part of this 

reconsideration action. The EPA is only accepting 

comments on the new source limits that are set 

forth in tables 1 and 2 of this preamble, which are 

the limits that are the subject of this reconsideration 

action. 

cost-effective 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 oil-fired 

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 

the project, and the incremental costeffectiveness 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-thefloor 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 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 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-tostack, 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. 

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 wetFGD 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 costeffectiveness 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 nonmercury HAP metals, with total nonmercury HAP metals and individual 

non-mercury HAP metals as alternative 

equivalent standards; Hg; and organic 

HAP. For oil-fired EGUs, the final rule 

regulates HCl and HF; filterable PM as 

a surrogate for total HAP metals, with 

individual HAP metals 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.6


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Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 71329 

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/MWh a ........ 3.0E–3 lb/GWh. 

New—Unit designed for low rank virgin coal .......................................... 9.0E–2 lb/MWh .......... 1.0E–2 lb/MWh a ........ NR. 

New—IGCC ............................................................................................. 7.0E–2 lb/MWh b ........

9.0E–2 lb/MWh c ........

2.0E–3 lb/MWh d ........ 3.0E–3 lb/GWh.e

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. 

aBeyond-the-floor value. 

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

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

dBased on best-performing similar source. 

eBased on permit levels in comments received. 

TABLE 2—PROPOSED REVISED ALTERNATE EMISSION LIMITATIONS FOR NEW EGUS

Subcategory/pollutant Coal-fired EGUs IGCC a Solid oil-derived 

SO2 ................................................ 1.0 lb/MWh ................................... 4.0E–1 lb/MWh b ........................... 1.0 lb/MWh. 

Total non-mercury 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. 

aBased on best-performing similar source unless otherwise noted. 

bBased 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 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 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 

considered three approaches to establish 

an operating limit based on emissions 

testing. The first approach 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 


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71330 Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 

7We are unaware of any new source that has 

commenced construction or reconstruction since 

May 3, 2011. 

second approach 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 

approach 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. See ‘‘75 Percent 

CPMS Operating Limit Approach— 

MATS Reconsideration’’ in rulemaking 

docket EPA–HQ–OAR–2009–0234. 

Even though this rule proposes the 

first approach, we solicit comments on 

the appropriateness of any of the three 

approaches to 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 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 sitespecific CPMS limit leading to followup 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 sitespecific 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 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 

commenced construction or 

reconstruction after May 3, 2011 is 

subject to the new source standards.7

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 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 accommodate operation of 


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Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 71331 

8 16 U.S.C. 796(18)(A) and 18 CFR 292.202(c). 

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.8 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 

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. 

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 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 reproposing 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 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 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 


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71332 Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 

9As 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. 

rate calculation procedure and 

monitoring requirements for PM to be 

similar to 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.9

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 

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. 

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.’’ 

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).’’ 

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.’’ 


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Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 71333 

10See ‘‘Regulatory Impact Analysis for the Final 

Mercury and Air Toxics Standards [EPA–452/R–11– 

011]’’ (docket entry EPA–HQ–OAR–2009–0234– 

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. 

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.10 Even if there were changes in 

costs for these units, such changes 

would likely be small relative to both 

the overall costs of the individual 

projects and the overall costs and 

benefits of the final rule, 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? 

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 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 (E.O.) 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 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 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-forprofit 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-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. Categories and 

entities potentially regulated by the 

final rule with applicable NAICS codes 

are provided in the Supplementary 

Information section of this action. 

According to the SBA size standards 

for NAICS code 221122 Utilities-Fossil 

Fuel Electric Power Generation, a firm 

is small if, including its affiliates, it is 

primarily engaged in the generation, 

transmission, and or distribution of 

electric energy for sale and its total 

electric output for the preceding fiscal 

year did not exceed 4 million MWh. 


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71334 Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 

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 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 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 

Risks and Safety Risks 

This action is not subject to EO 13045 

(62 FR 19885, April 23, 1997) because 

it is not economically significant as 

defined in EO 12866. The EPA has 

evaluated the environmental health or 

safety effects of the final 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 

rulemaking docket EPA–HQ–OAR– 

2009–0234. 

The public is invited to submit 

comments or identify peer-reviewed 

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 (Pub. L. 104–113; 

15 U.S.C. 272 note) directs EPA to use 

voluntary consensus standards in their 

regulatory and procurement activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impracticable. Voluntary consensus 

standards are technical standards (e.g., 

material specifications, test methods, 

sampling procedures, business 

practices) developed or adopted by one 

or more voluntary consensus bodies. 

The NTTAA requires EPA to provide 

Congress, through the OMB, with 

explanations when EPA decides not to 

use available and applicable voluntary 

consensus standards. 

During the development of the final 

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 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 

relevant assumptions, we project that 

this rule will result in no significant 

change in emission reductions. 


wreier-aviles on DSK5TPTVN1PROD with 
Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 71335 

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: November 16, 2012. 

Lisa P. Jackson, 

Administrator. 

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, coaloil mixtures, and coal-water mixtures 

are included in this definition for the 

purposes of this subpart. 

* * * * * 

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 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 combinedcycle 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, coalderived gas, producer gas, coke oven 

gas, or any gaseous fuel produced in a 

process which might result in highly 

variable sulfur content or heating value. 

* * * * * 

■ 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. 

* * * * * 

(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) introductory text, 

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

introductory text, (o)(3)(i), and (o)(4) 

introductory text to read as follows: 

§ 60.48Da Compliance provisions. 

(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 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-out-of-control hourly emission rates 

of the operating day(s) not meeting the 

minimum 18 hours non-out-of-control 

data daily average requirement are 

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

boiler operating day with 18 hours or 

more of non-out-of-control PM CEMS 

data to determine compliance. For 

affected facilities for which 

construction, 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 


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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 conduct each subsequent 

performance test within 12 calendar 

months following the date the previous 

performance test was required to be 

conducted. You must conduct each 

performance test according to the 

requirements in § 60.8 using the test 

methods and procedures in § 60.50Da. 

The owner or operator of an affected 

facility that has not operated for 60 

consecutive calendar days prior to the 

date that the subsequent performance 

test would have been required had the 

unit been operating is not required to 

perform the subsequent performance 

test until 30 calendar days after the next 

boiler operating day. Requests for 

additional 30 day extensions shall be 

granted by the relevant air division or 

office director of the appropriate 

Regional Office of the U.S. EPA. 

(2) You must monitor the performance 

of each electrostatic precipitator or 

fabric filter (baghouse) operated to 

comply with the applicable PM 

emissions limit in § 60.42Da using a 

continuous opacity monitoring system 

(COMS) according to the requirements 

in paragraphs (o)(2)(i) through (vi) 

unless you elect to comply with one of 

the alternatives provided in paragraphs 

(o)(3) and (o)(4) of this section, as 

applicable to your control device. 

* * * * * 

(3) As an alternative to complying 

with the requirements of paragraph 

(o)(2) of this section, an owner or 

operator may elect to monitor the 

performance of an electrostatic 

precipitator (ESP) operated to comply 

with the applicable PM emissions limit 

in § 60.42Da using an ESP predictive 

model developed in accordance with 

the requirements in paragraphs (o)(3)(i) 

through (v) of this section. 

(i) You must calibrate the ESP 

predictive model with each PM control 

device used to comply with the 

applicable PM emissions limit in 

§ 60.42Da operating under normal 

conditions. In cases when a wet 

scrubber is used in combination with an 

ESP to comply with the PM emissions 

limit, the wet scrubber must be 

maintained and operated. 

* * * * * 

(4) As an alternative to complying 

with the requirements of paragraph 

(o)(2) of this section, an owner or 

operator may elect to monitor the 

performance of a fabric filter (baghouse) 

operated to comply with the applicable 

PM emissions limit in § 60.42Da by 

using a bag leak detection system 

according to the requirements in 

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

section. 

* * * * * 

■ 5. Amend § 60.49Da by: 

■ 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. 

* * * * * 

(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 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 sitespecific 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, 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 


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emissions limit in § 60.42Da may install, 

certify, operate, and maintain a CEMS 

for measuring PM emissions according 

to the requirements of paragraph (v) of 

this section. 

* * * * * 

■ 6. Revise § 60.50Da paragraph (f) to 

read as follows: 

§ 60.50Da Compliance determination 

procedures and methods. 

* * * * * 

(f) The owner or operator of an 

electric utility combined cycle gas 

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. In § 63.9982, revise paragraphs (a) 

introductory text, (b), and (c) to read as 

follows: 

§ 63.9982 What is the affected source of 

this subpart? 

* * * * * 

(a) This subpart applies to each 

individual or group of two or more new, 

reconstructed, or existing affected 

source(s) as described in paragraphs 

(a)(1) and (2) of this section within a 

contiguous area and under common 

control. 

* * * * * 

(b) An EGU is new if you commence 

construction of the coal- or oil-fired 

EGU after May 3, 2011. 

(c) An EGU is reconstructed if you 

meet the reconstruction criteria as 

defined in § 63.2, or if you commence 

reconstruction after May 3, 2011. 

* * * * * 

■ 9. In § 63.10005, revise 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 sitespecific 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 sitespecific operating parameters as 

provided in § 63.10000(c)(2)(iii) or 

(ii) Use an HCl CEMS and/or HF 

CEMS. 

* * * * * 

■ 10. In § 63.10006, revise paragraph (c) 

to read as follows: 

§ 63.10006 When must I conduct 

subsequent performance tests or tune-ups? 

* * * * * 

(c) Except where paragraphs (a) or (b) 

of this section apply, or where you 

install, certify, and operate a PM CEMS 

to demonstrate compliance with a 

filterable PM emissions limit, for liquid 

oil-, solid oil-derived fuel-, and coalfired 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. In § 63.10007, revise paragraph (c) 

to read as follows: 

§ 63.10007 What methods and other 

procedures must I use for the performance 

tests? 

* * * * * 

(c) If you choose to comply with the 

filterable PM emission limit and 

demonstrate continuous performance 

using a PM CPMS for an applicable 

emission limit as provided for in 

§ 63.10000(c), you must also establish 

an operating limit according to 

§ 63.10011(b), § 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. In § 63.10009, revise paragraphs 

(b)(2) and (b)(3) to read as follows: 

§ 63.10009 May I use emissions averaging 

to comply with this subpart? 

* * * * * 

(b) * * * 

(2) Weighted 30-boiler operating day 

rolling average emissions rate equations 

for pollutants other than Hg. Use 

equation 2a or 2b to calculate the 30 day 

rolling average emissions daily. 

Where: 

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

lb/MWh) from unit i’s CEMS for the 

preceding 30-group boiler operating 

days, 

Rmi = hourly heat input or gross 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, 


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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. 

Where: 

variables with similar names share the 

descriptions for Equation 2a, 

Smi = steam generation in units of pounds 

from unit i that uses CEMS for the 

preceding 30-group boiler operating 

days, 

Cfmi = conversion factor, calculated from the 

most recent compliance test results, in 

units of heat input per pound of steam 

generated or gross electrical output per 

pound of steam generated, from unit i 

that uses CEMS from the preceding 30 

group boiler operating days, 

Sti = steam generation in units of pounds 

from unit i that uses emissions testing, 

and 

Cfti = conversion factor, calculated from the 

most recent compliance test results, in 

units of heat input per pound of steam 

generated or gross electrical output per 

pound of steam generated, from unit i 

that uses emissions testing. 

(3) Weighted 90-boiler operating day 

rolling average emissions rate equations 

for Hg emissions from EGUs in the 

‘‘coal-fired unit not low rank virgin 

coal’’ subcategory. Use equation 3a or 3b 

to calculate the 90-day rolling average 

emissions daily. 

Where: 

Heri = hourly emission rate from unit i’s 

CEMS or Hg sorbent trap monitoring 

system for the preceding 90-group boiler 

operating days, 

Rmi = hourly heat input or gross electrical 

output from unit i for the preceding 90- 

group boiler operating days, 

p = number of EGUs in emissions averaging 

group that rely on CEMS, 

n = number of hourly rates collected over the 

90-group boiler operating days, 

Teri = Emissions rate from most recent 

emissions test of unit i in terms of lb/ 

heat input or lb/gross electrical output, 

Rti = Total heat input or gross electrical 

output of unit i for the preceding 90- 

boiler operating days, and 

m = number of EGUs in emissions averaging 

group that rely on emissions testing. 

Where: 

variables with similar names share the 

descriptions for Equation 2a, 

Smi = steam generation in units of pounds 

from unit i that uses CEMS or a Hg 

sorbent trap monitoring for the preceding 

90-group boiler operating days, 

Cfmi = conversion factor, calculated from the 

most recent compliance test results, in 

units of heat input per pound of steam 

generated or gross electrical output per 

pound of steam generated, from unit i 

that uses CEMS or sorbent trap 

monitoring from the preceding 90-group 

boiler operating days, 

Sti = steam generation in units of pounds 

from unit i that uses emissions testing, 

and 

Cfti = conversion factor, calculated from the 

most recent emissions test results, in 

units of heat input per pound of steam 

generated or gross electrical output per 

pound of steam generated, from unit i 

that uses emissions testing. 

* * * * * 

■ 13. In § 63.10010, revise 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 sitespecific 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. In § 63.10011, revise paragraphs (f) 

and (g) to read as 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 

oil-derived fuel-fired EGU. 

■ 15. Amend § 63.10021 by adding 

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

follows: 

§ 63.10021 How do I demonstrate 

continuous compliance with the emission 

limitations, operating limits, and work 

practice standards? 

* * * * * 

(c) * * * 

(1) For any exceedance of the 30- 

boiler operating day PM CPMS average 

value from the established operating 

parameter limit for an EGU subject to 

the emissions limits in Table 1 to this 

subpart, you must: 

(i) Within 48 hours of the exceedance, 

visually inspect the air pollution control 

device (APCD); 


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(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 reestablish 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 of this 

subpart. 

* * * * * 

■ 16. In § 63.10023, revise 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 based on the highest 1- 

hour average PM CPMS output value 

recorded during the performance test. 

* * * * * 

■ 17. In § 63.10030, revise paragraphs 

(b), (c), and (d) to read as follows: 

§ 63.10030 What notifications must I 

submit and when? 

* * * * * 

(b) As specified in § 63.9(b)(2), if you 

startup your EGU that is an affected 

source before April 16, 2012, you must 

submit an Initial Notification not later 

than 120 days after April 16, 2012. 

(c) As specified in § 63.9(b)(4) and 

(b)(5), if you startup your new or 

reconstructed EGU that is an affected 

source on or after April 16, 2012, you 

must submit an Initial Notification not 

later than 15 days after the actual date 

of startup of the EGU that is an affected 

source. 

(d) When you are required to conduct 

a performance test, you must submit a 

Notification of Intent to conduct a 

performance test at least 60 days before 

the performance test is scheduled to 

begin. 

* * * * * 

■ 18. Amend § 63.10042 by: 

■ a. Revising the definitions of ‘‘Boiler 

operating day,’’ ‘‘Shutdown’’, ‘‘Startup’’, 

and ‘‘Unit designed for coal > 8,300 Btu/ 

lb subcategory’’; and 

■ b. Adding, in alphabetical order, 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 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 

first-ever 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 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. Revise Table 1 to Subpart UUUUU 

of Part 63 to read as follows: 

Table 1 to Subpart UUUUU of Part 63— 

Emission Limits for New or 

Reconstructed EGUs 

As stated in § 63.9991, you must 

comply with the following applicable 

emission limits: 

If your EGU is in this subcategory . . . For the following 

pollutants . . . 

You must meet the 

following emission 

limits and work 

practice standards 

. . . 

Using these requirements, as appropriate 

(e.g., specified sampling volume or test run 

duration) and limitations with the test 

methods in Table 5 . . . 

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

matter (PM).

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

OR OR 

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

OR OR 

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

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

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

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

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


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If your EGU is in this subcategory . . . For the following 

pollutants . . . 

You must meet the 

following emission 

limits and work 

practice standards 

. . . 

Using these requirements, as appropriate 

(e.g., specified sampling volume or test run 

duration) and limitations with the test 

methods in Table 5 . . . 

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

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

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

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

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

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

b. Hydrogen chloride 

(HCl).

1.0E–2 lb/MWh ......... For Method 26A, collect a minimum of 3 

dscm per run. 

For ASTM D6348–03 2 or Method 320, 

sample for a minimum of 1 hour. 

OR 

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

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

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

matter (PM).

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

OR OR 

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

OR OR 

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

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

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

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

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

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

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

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

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

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

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

b. Hydrogen chloride 

(HCl).

1.0E–2 lb/MWh ......... For Method 26A, collect a minimum of 3 

dscm per run. 

For ASTM D6348–03 2 or Method 320, 

sample for a minimum of 1 hour. 

OR 

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

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

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

matter (PM).

7.0E–2 lb/MWh 4 .......

9.0E–2 lb/MWh 5 .......

Collect a minimum of 1 dscm per run. 

OR OR 

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

OR OR 

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

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

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

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

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

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

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

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

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

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

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

b. Hydrogen chloride 

(HCl).

2.0E–3 lb/MWh ......... For Method 26A, collect a minimum of 1 

dscm per run; for Method 26, collect a 

minimum of 120 liters per run. 

For ASTM D6348–03 2 or Method 320, 

sample for a minimum of 1 hour. 

OR 

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

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

4. Liquid oil-fired unit—continental (excluding 

limited-use liquid oil-fired subcategory 

units).

a. Filterable particulate 

matter (PM).

OR 

Total HAP metals .............

OR 

4.0E–1 lb/MWh 1 .......

OR 

2.0E–4 lb/MWh .........

OR 

Collect a minimum of 1 dscm per run. 

Collect a minimum of 2 dscm per run. 

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

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


wreier-aviles on DSK5TPTVN1PROD with 
Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 71341 

If your EGU is in this subcategory . . . For the following 

pollutants . . . 

You must meet the 

following emission 

limits and work 

practice standards 

. . . 

Using these requirements, as appropriate 

(e.g., specified sampling volume or test run 

duration) and limitations with the test 

methods in Table 5 . . . 

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

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

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

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

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

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

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

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

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

Mercury (Hg) .................... 1.0E–4 lb/GWh ......... For Method 30B sample volume determination (Section 8.2.4), the estimated Hg 

concentration should nominally be <1⁄2

the standard. 

b. Hydrogen chloride 

(HCl).

4.0E–4 lb/MWh ......... For Method 26A, collect a minimum of 3 

dscm per run. 

For ASTM D6348–03 2 or Method 320, 

sample for a minimum of 1 hour. 

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

dscm per run. 

For ASTM D6348–03 2 or Method 320, 

sample for a minimum of 1 hour. 

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

matter (PM).

OR 

Total HAP metals .............

OR 

2.0E–1 lb/MWh 1 .......

OR 

7.0E–3 lb/MWh .........

OR 

Collect a minimum of 1 dscm per run. 

Collect a minimum of 1 dscm per run. 

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

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

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

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

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

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

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

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

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

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

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

Mercury (Hg) .................... 4.0E–4 lb/GWh ......... For Method 30B sample volume determination (Section 8.2.4), the estimated Hg 

concentration should nominally be <1⁄2

the standard. 

b. Hydrogen chloride 

(HCl).

2.0E–3 lb/MWh ......... For Method 26A, collect a minimum of 1 

dscm per run; for Method 26, collect a 

minimum of 120 liters per run. 

For ASTM D6348–03 2 or Method 320, 

sample for a minimum of 1 hour. 

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

dscm per run. 

For ASTM D6348–03 2 or Method 320, 

sample for a minimum of 1 hour. 

6. Solid oil-derived fuel-fired unit. ................... a. Filterable particulate 

matter (PM).

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

OR OR 

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

OR OR 

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

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

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

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

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

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

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

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

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

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

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

b. Hydrogen chloride 

(HCl).

4.0E–4 lb/MWh ......... For Method 26A, collect a minimum of 3 

dscm per run. 

For ASTM D6348–03 2 or Method 320, 

sample for a minimum of 1 hour. 


wreier-aviles on DSK5TPTVN1PROD with 
71342 Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 

If your EGU is in this subcategory . . . For the following 

pollutants . . . 

You must meet the 

following emission 

limits and work 

practice standards 

. . . 

Using these requirements, as appropriate 

(e.g., specified sampling volume or test run 

duration) and limitations with the test 

methods in Table 5 . . . 

OR 

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

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

1Gross electric output. 

2 Incorporated by reference, see § 63.14. 

3You may not use the alternate SO2 limit if your EGU does not have some form of FGD system and SO2 CEMS installed. 4 Duct burners on syngas; gross electric output. 

5 Duct burners on natural gas; gross electric output. 

■ 20. Revise Table 3 to Subpart UUUUU 

of Part 63 to read as follows: 

Table 3 to Subpart UUUUU of Part 63 

— Work Practice Standards 

As stated in §§ 63.9991, you must 

comply with the following applicable 

work practice standards: 

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

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

48 calendar months if neural network combustion optimization software is employed, as specified in 

§ 63.10021(e). 

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

48 calendar months if neural network combustion optimization software is employed, as specified in 

§ 63.10021(e). 

3. A coal-fired, liquid oil-fired, 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 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 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. Revise Table 4 to Subpart UUUUU 

of Part 63 to read as follows: 

Table 4 to Subpart UUUUU of Part 63— 

Operating Limits for EGUs 

As stated in §§ 63.9991, you must 

comply with the applicable operating 

limits: 


wreier-aviles on DSK5TPTVN1PROD with 
Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 71343 

If you demonstrate compliance using . . . You must meet these operating limits . . . 

1. PM CPMS for an existing EGU.Maintain the 30-boiler operating day rolling average PM CPMS output at or below the highest 1-hour average measured during the most recent performance test demonstrating compliance with the filterable PM, total non-mercury 

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

2. PM CPMS for a new 

EGU.

Maintain the 30-boiler operating day rolling average PM CPMS output at or below the highest 1-hour average PM 

CPMS output value recorded 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. Revise footnote 4 of Table 5 to 

Subpart UUUUU of Part 63 to read as 

follows: 

Table 5 to Subpart UUUUU of Part 63— 

Performance Testing Requirements 

* * * * * 

4When 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 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. Revise Table 6 to Subpart UUUUU 

of Part 63 to read as follows: 

Table 6 to Subpart UUUUU of Part 63— 

Establishing PM CPMS Operating 

Limits 

As stated in § 63.10007, you must 

comply with the following requirements 

for establishing operating limits: 

If you have an applicable 

emission limit for . . . 

And you choose to establish PM CPMS operating 

limits, you must . . . 

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

procedures . . . 

1. Filterable Particulate 

matter (PM), total nonmercury HAP metals, individual non-mercury 

HAP metals, total HAP 

metals, or individual 

HAP metals for an existing EGU.

Install, certify, maintain, 

and operate a PM 

CPMS for monitoring 

emissions discharged to 

the atmosphere according to § 63.10010(h)(1).

Establish a site-specific 

operating limit in units of 

PM CPMS output signal 

(e.g., milliamps, mg/ 

acm, or other raw signal).

Data from the PM CPMS 

and the PM or HAP metals performance tests.

1. Collect PM CPMS output data during the entire period of the performance tests. 

2. Record the average 

hourly PM CPMS output 

for each test run in the 

three run performance 

test. 

3. Determine the highest 

1-hour average PM 

CPMS measured during 

the performance test 

demonstrating compliance with the filterable 

PM or HAP metals emissions limitations. 

2. Filterable Particulate 

matter (PM), total nonmercury HAP metals, individual non-mercury 

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 site-specific 

operating limit in units of 

PM CPMS output signal 

(e.g., milliamps, mg/ 

acm, or other raw signal).

Data from the PM CPMS 

and the PM or HAP metals performance tests.

1. Collect PM CPMS output data during the entire period of the performance tests. 

2. Record the average 

hourly PM CPMS output 

for each test run in the 

three run performance 

test. 

3. Determine the highest 

1-hour average PM 

CPMS measured during 

the performance run 

demonstrating compliance with the filterable 

PM or HAP metals emissions limitations. 

■ 24. Revise Table 7 to Subpart UUUUU 

of Part 63 to read as follows: 

Table 7 to Subpart UUUUU of Part 63— 

Demonstrating Continuous Compliance 

As stated in § 63.10021, you must 

show continuous compliance with the 

emission limitations for affected sources 

according to the following: 


wreier-aviles on DSK5TPTVN1PROD with 
71344 Federal Register / Vol. 77, No. 231 / Friday, November 30, 2012 / Rules and Regulations 

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 oil-fired EGUs 

for HCl and HF emission limit monitoring.

If applicable, by conducting the monitoring in accordance with an approved sitespecific 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 oil-fired, or 

solid oil-derived fuel-fired EGUs during startup.

Operating in accordance with Table 3. 

7. Work practice standards for coal-fired, liquid oil-fired, or 

solid oil-derived fuel-fired EGUs during shutdown.

Operating in accordance with Table 3. 

■ 25. Revise sections 4.1 and 5.2.2.2 to 

Appendix A to Subpart UUUUU of Part 

63 to read as follows: 

Appendix A to Subpart UUUUU—Hg 

Monitoring Provisions 

4.1 Certification Requirements. All Hg 

CEMS and sorbent trap monitoring systems 

and the additional monitoring systems used 

to continuously measure Hg emissions in 

units of the applicable emissions standard in 

accordance with this appendix must be 

certified in a timely manner, such that the 

initial compliance demonstration is 

completed no later than the applicable date 

in § 63.9984(f). 

* * * * * 

5.2.2.2 The same RATA performance 

criteria specified in Table A–2 for Hg CEMS 

shall apply to the annual RATAs of the 

sorbent trap monitoring system. 

* * * * * 

■ 26. Revise section 3.1.2.1.3 and the 

heading 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 

* * * * * 

[FR Doc. 2012–28729 Filed 11–29–12; 8:45 am] 

BILLING CODE 6560–50–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 271 and 272 

[EPA–R06–RCRA–2012–0473; FRL–9745–1] 

Texas: Final Authorization of Stateinitiated Changes and Incorporation by 

Reference of State Hazardous Waste 

Management Program 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Direct final rule. 

SUMMARY: During a review of Texas’ 

regulations, the EPA identified a variety 

of State-initiated changes to its 

hazardous waste program under the 

Resource Conservation and Recovery 

Act (RCRA). We have determined that 

these changes are minor and satisfy all 

requirements needed to qualify for Final 

authorization and are authorizing the 

State-initiated changes through this 

Direct Final action. 

The Solid Waste Disposal Act, as 

amended, commonly referred to as the 

Resource Conservation and Recovery 

Act (RCRA), allows the Environmental 

Protection Agency (EPA) to authorize 

States to operate their hazardous waste 

management programs in lieu of the 

Federal program. The EPA uses the 

regulations entitled ‘‘Approved State 

Hazardous Waste Management 

Programs’’ to provide notice of the 

authorization status of State programs 

and to incorporate by reference those 

provisions of the State statutes and 

regulations that will be subject to the 

EPA’s inspection and enforcement. The 

rule codifies in the regulations the prior 

approval of Texas’ hazardous waste 

management program and incorporates 

by reference authorized provisions of 

the State’s statutes and regulations. 

DATES: This regulation is effective 

January 29, 2013, unless the EPA 

receives adverse written comment on 

the codification of the Texas authorized 

RCRA program by the close of business 

December 31, 2012. If the EPA receives 

such comments, it will publish a timely 

withdrawal of this direct final rule in 

the Federal Register informing the 

public that this rule will not take effect. 

The incorporation by reference of 

authorized provisions in the Texas 

statutes and regulations contained in 

this rule is approved by the Director of 

the Federal Register as of January 29, 

2013 in accordance with 5 U.S.C. 552(a) 

and 1 CFR part 51. 

ADDRESSES: Submit your comments by 

one of the following methods: 

1. Federal eRulemaking Portal: 

http://www.regulations.gov. Follow the 

on-line instructions for submitting 

comments. 

2. Email: patterson.alima@epa.gov or 

banks.julia@epa.gov. 

3. Mail: Alima Patterson, Region 6, 

Regional Authorization Coordinator, or 

Julia Banks, Codification Coordinator, 

State/Tribal Oversight Section (6PD–O), 

Multimedia Planning and Permitting 

Division, EPA Region 6, 1445 Ross 

Avenue, Dallas, Texas 75202–2733. 

4. Hand Delivery or Courier: Deliver 

your comments to Alima Patterson, 

Region 6, Regional Authorization 

Coordinator, or Julia Banks, Codification 

Coordinator, State/Tribal Oversight 

Section (6PD–O), Multimedia Planning 

and Permitting Division, EPA Region 6, 

1445 Ross Avenue, Dallas, Texas 75202– 

2733. 


wreier-aviles on DSK5TPTVN1PROD with