Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 24073 

minimize litigation, eliminate 

ambiguity, and reduce burden. 

10. Protection of Children 

We have analyzed this rule under 

Executive Order 13045, Protection of 

Children from Environmental Health 

Risks and Safety Risks. This rule is not 

an economically significant rule and 

does not create an environmental risk to 

health or risk to safety that may 

disproportionately affect children. 

11. Indian Tribal Governments 

This rule does not have tribal 

implications under Executive Order 

13175, Consultation and Coordination 

with Indian Tribal Governments, 

because it does not have a substantial 

direct effect on one or more Indian 

tribes, 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. 

12. Energy Effects 

This action is not a ‘‘significant 

energy action’’ under Executive Order 

13211, Actions Concerning Regulations 

That Significantly Affect Energy Supply, 

Distribution, or Use. 

13. Technical Standards 

This rule does not use technical 

standards. Therefore, we did not 

consider the use of voluntary consensus 

standards. 

14. Environment 

We have analyzed this rule under 

Department of Homeland Security 

Management Directive 023–01 and 

Commandant Instruction M16475.lD, 

which guide the Coast Guard in 

complying with the National 

Environmental Policy Act of 1969 

(NEPA)(42 U.S.C. 4321–4370f), and 

have determined that this action is one 

of a category of actions that do not 

individually or cumulatively have a 

significant effect on the human 

environment. This rule involves 

establishing a safety zone for a fireworks 

display launch site and fallout area and 

is expected to have no impact on the 

water or environment. This zone is 

designed to protect mariners and 

spectators from the hazards associated 

with aerial fireworks displays. This rule 

is categorically excluded from further 

review under paragraph 34 (g) of Figure 

2–1 of the Commandant Instruction. An 

environmental analysis checklist 

supporting this determination and a 

Categorical Exclusion Determination are 

available in the docket where indicated 

under ADDRESSES. We seek any 

comments or information that may lead 

to the discovery of a significant 

environmental impact from this rule. 

List of Subjects in 33 CFR Part 165 

Harbors, Marine safety, Navigation 

(water), Reporting and recordkeeping 

requirements, Security measures, and 

Waterways. 

For the reasons discussed in the 

preamble, the Coast Guard amends 33 

CFR part 165 as follows: 

PART 165—REGULATED NAVIGATION 

AREAS AND LIMITED ACCESS AREAS 

■ 1. The authority citation for part 165 

continues to read as follows: 

Authority: 33 U.S.C. 1231; 46 U.S.C. 

Chapter 701, 3306, 3703; 50 U.S.C. 191, 195; 

33 CFR 1.05–1, 6.04–1, 6.04–6, 160.5; Pub. L. 

107–295, 116 Stat. 2064; Department of 

Homeland Security Delegation No. 0170.1. 

■ 2. Add temporary § 165.T05–0259 to 

read as follows: 

§ 165.T05–0259 Safety Zone; Pasquotank 

River; Elizabeth City, NC. 

(a) Definitions. For the purposes of 

this section, Captain of the Port means 

the Commander, Sector North Carolina. 

Representative means any Coast 

Guard commissioned, warrant, or petty 

officer who has been authorized to act 

on the behalf of the Captain of the Port. 

(b) Location. The following area is a 

safety zone: Specified waters of the 

Captain of the Port, Sector North 

Carolina, as defined in 33 CFR 3.25–20, 

all waters of the Pasquotank River 

within a 300 yard radius of the 

fireworks launch barge in approximate 

position latitude 36°17′47′′ N longitude 

076°12′17′′, located near Machelhe 

Island. 

(c) Regulations. (1) The general 

regulations contained in § 165.23 of this 

part apply to the area described in 

paragraph (b) of this section. 

(2) Persons or vessels requiring entry 

into or passage through any portion of 

the safety zone must first request 

authorization from the Captain of the 

Port, or a designated representative, 

unless the Captain of the Port 

previously announced via Marine Safety 

Radio Broadcast on VHF Marine Band 

Radio channel 22 (157.1 MHz) that this 

regulation will not be enforced in that 

portion of the safety zone. The Captain 

of the Port can be contacted at telephone 

number (910) 343–3882 or by radio on 

VHF Marine Band Radio, channels 13 

and 16. 

(d) Enforcement. The U.S. Coast 

Guard may be assisted in the patrol and 

enforcement of the zone by Federal, 

State, and local agencies. 

(e) Enforcement period. This section 

will be enforced on May 18, 2013 from 

8 p.m. to 11 p.m. unless cancelled 

earlier by the Captain of the Port. 

Dated: April 12, 2013. 

A. Popiel, 

Captain, U.S. Coast Guard, Captain of the 

Sector North Carolina. 

[FR Doc. 2013–09609 Filed 4–23–13; 8:45 am] 

BILLING CODE 9110–04–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 60 and 63 

[EPA–HQ–OAR–2009–0234; EPA–HQ–OAR– 

2011–0044; FRL–9789–5] 

RIN 2060–AR62 

Reconsideration of Certain New 

Source Issues: National Emission 

Standards for Hazardous Air Pollutants 

From Coal- and Oil-Fired Electric Utility 

Steam Generating Units and Standards 

of Performance for Fossil-Fuel-Fired 

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

Generating Units 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule; notice of final action 

on reconsideration. 

SUMMARY: The EPA is taking final action 

on its reconsideration of certain issues 

in the final rules titled, ‘‘National 

Emission Standards for Hazardous Air 

Pollutants from Coal- and Oil-fired 

Electric Utility Steam Generating Units 

and Standards of Performance for 

Fossil-Fuel-Fired Electric Utility, 

Industrial-Commercial-Institutional, and 

Small Industrial-CommercialInstitutional Steam Generating Units.’’ 

The National Emission Standards for 

Hazardous Air Pollutants (NESHAP) 

rule issued pursuant to Clean Air Act 

(CAA) section 112 is referred to as the 

Mercury and Air Toxics Standards 

(MATS) NESHAP, and the New Source 

Performance Standards rule issued 

pursuant to CAA section 111 is referred 

to as the Utility NSPS. The 

Administrator received petitions for 

reconsideration of certain aspects of the 

MATS NESHAP and the Utility NSPS. 

On November 30, 2012, the EPA 

granted reconsideration of, proposed, 

and requested comment on a limited set 

of issues. We also proposed certain 

technical corrections to both the MATS 

NESHAP and the Utility NSPS. The EPA 

is now taking final action on the revised 

new source numerical standards in the 

MATS NESHAP and the definitional 

and monitoring provisions in the Utility 

NSPS that were addressed in the 


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proposed reconsideration rule. As part 

of this action, the EPA is also making 

certain technical corrections to both the 

MATS NESHAP and the Utility NSPS. 

The EPA is not taking final action on 

requirements applicable during periods 

of startup and shutdown in the MATS 

NESHAP or on startup and shutdown 

provisions related to the PM standard in 

the Utility NSPS. 

DATES: The effective date of the rule is 

April 24, 2013. 

Docket. The EPA established two 

dockets for this action: Docket ID EPA– 

HQ–OAR–2011–0044 (NSPS action) and 

Docket ID EPA–HQ–OAR–2009–0234 

(MATS NESHAP action). All documents 

in the dockets are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available (e.g., confidential 

business information (CBI) or other 

information whose disclosure is 

restricted by statute). Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy form. Publicly available docket 

materials are available either 

electronically in http:// 

www.regulations.gov or in hard copy at 

the EPA Docket Center, Room 3334, 

1301 Constitution Avenue NW., 

Washington, DC. The Public Reading 

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

p.m., Monday through Friday, excluding 

legal holidays. The telephone number 

for the Public Reading Room is (202) 

566–1744, and the telephone number for 

the Air Docket is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: For 

the MATS NESHAP action: Mr. William 

Maxwell, Energy Strategies Group, 

Sector Policies and Programs Division, 

(D243–01), Office of Air Quality 

Planning and Standards, U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711; Telephone number: (919) 541– 

5430; Fax number (919) 541–5450; 

Email address: maxwell.bill@epa.gov. 

For the NSPS action: Mr. Christian 

Fellner, Energy Strategies Group, Sector 

Policies and Programs Division, (D243– 

01), Office of Air Quality Planning and 

Standards, U.S. Environmental 

Protection Agency, Research Triangle 

Park, North Carolina 27711; Telephone 

number: (919) 541–4003; Fax number 

(919) 541–5450; Email address: 

fellner.christian@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Outline. The information presented in 

this preamble is organized as follows: 

I. General Information 

A. Does this action apply to me? 

B. How do I obtain a copy of this 

document? 

C. Judicial Review 

II. Background 

III. Summary of Today’s Action 

IV. Summary of Final Action and Changes 

Since Proposal—MATS NESHAP New 

Source Issues 

V. Summary of Final Action and Changes 

Since Proposal—Utility NSPS 

VI. Technical Corrections and Clarifications 

VII. Impacts of This Final Rule 

A. Summary of Emissions Impacts, Costs 

and Benefits 

B. What are the air impacts? 

C. What are the energy impacts? 

D. What are the compliance costs? 

E. What are the economic and employment 

impacts? 

F. What are the benefits of the final 

standards? 

VIII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. General Information 

A. Does this action apply to me? 

Categories and entities potentially 

affected by today’s action include: 

Category NAICS code1 Examples of potentially regulated entities 

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

Federal government .................................. 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. How do I obtain a copy of this 

document? 

In addition to being available in the 

docket, electronic copies of these final 

rules will be available on the 

Worldwide Web (WWW) through the 

Technology Transfer Network (TTN). 

Following signature, a copy of the 

action will be posted on the TTN’s 

policy and guidance page for newly 

proposed or promulgated rules at the 

following address: http://www.epa.gov/ 

ttn/oarpg/. The TTN provides 

information and technology exchange in 

various areas of air pollution control. 

C. Judicial Review 

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

judicial review of this final rule is 

available only by filing a petition for 

review in the U.S. Court of Appeals for 

the District of Columbia Circuit by June 

24, 2013. Under CAA section 

307(d)(7)(B), only an objection to this 

final rule that was raised with 

reasonable specificity during the period 

for public comment can be raised during 

judicial review. Note, under CAA 

section 307(b)(2), the requirements 

established by this final rule may not be 

challenged separately in any civil or 

criminal proceedings brought by the 

EPA to enforce these requirements. 

II. Background 

The final MATS NESHAP and the 

Utility NSPS rules were published in 

the Federal Register at 77 FR 9304 on 


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1The EPA is also still reviewing the other issues 

raised in the petitions for reconsideration and is not 

taking any action at this time with respect to those 

issues. 

2As the final MATS rule established a filterable 

PM (fPM) limit, every reference in this preamble to 

a PM limit means filterable PM. 

3The final rule included certain alternative limits 

(see 77 FR 9367–9369). 

February 16, 2012. Following 

promulgation of the final rules, the 

Administrator received petitions for 

reconsideration of numerous provisions 

of both the MATS NESHAP and the 

Utility NSPS pursuant to CAA section 

307(d)(7)(B). Copies of the MATS 

NESHAP petitions are provided in 

rulemaking docket EPA–HQ–OAR– 

2009–0234. Copies of the Utility NSPS 

petitions are provided in rulemaking 

docket EPA–HQ–OAR–2011–0044. On 

November 30, 2012, the proposal 

granting reconsideration of certain 

issues in the MATS NESHAP and 

Utility NSPS was published in the 

Federal Register at 77 FR 71323. 

III. Summary of Today’s Action 

This final action amends certain 

provisions of the final rule issued by the 

EPA on February 16, 2012. Through an 

August 2, 2012, notice (77 FR 45967), 

the EPA delayed the effective date of the 

February 2012 MATS rule for new 

sources only. That stay was limited to 

90 days and has since expired. The 

February 2012 final rule is and remains 

in effect for all sources. 

The November 30, 2012, proposed 

reconsideration rule proposed: (1) 

Certain revised new source numerical 

standards in the MATS NESHAP, (2) 

requirements applicable during periods 

of startup and shutdown in the MATS 

NESHAP, (3) startup and shutdown 

provisions related to the particulate 

matter (PM) standard in the Utility 

NSPS, and (4) definitional and 

monitoring provisions in the Utility 

NSPS. We also proposed certain 

technical corrections to both the MATS 

NESHAP and the Utility NSPS. We are 

taking final action today on the revised 

numerical new source MATS NESHAP 

limits, the definitional and monitoring 

issues in the Utility NSPS, and all of the 

technical corrections not related to 

startup/shutdown issues. 

This summary of the final rule reflects 

the changes to 40 CFR Part 63, subpart 

UUUUU, and 40 CFR Part 60, subpart 

Da (77 FR 9304; February 16, 2012) 

made in this regard. 

As noted above, in the proposed 

reconsideration rule, the EPA took 

comment on the requirements in the 

MATS NESHAP applicable during 

startup and shutdown, including the 

definitions of startup and shutdown. 

The EPA also took comment on the 

startup and shutdown provisions 

relating to the PM standard in the 

Utility NSPS. The EPA received 

considerable comments regarding these 

startup and shutdown provisions, 

including data and information relevant 

to the proposed work practice standard 

that applies in such periods. The EPA 

is not taking final action on the startup 

and shutdown provisions at this time as 

it needs additional time to consider and 

evaluate the comments and data 

provided.1 The Agency is currently 

reviewing all of the comments received 

on the startup and shutdown issues and 

intends to act promptly to address these 

issues. We note that no existing sources 

will have to comply with the existing 

source MATS standards before April 16, 

2015. Further, no new sources are 

currently under construction and it 

takes years to complete construction. 77 

FR 71330, fn. 7. As such, there will be 

sufficient time for the Agency to review 

the comments submitted concerning the 

proposed startup and shutdown 

provisions and take appropriate action 

well in advance of any new source being 

subject to those provisions. 

As described below, on the basis of 

information provided since the 

reconsideration proposal, today’s action 

revises certain new source numerical 

limits in the MATS NESHAP. 

Specifically, the EPA is finalizing 

revised hydrogen chloride (HCl), 

filterable PM (fPM),2 sulfur dioxide 

(SO2), lead (Pb), and selenium emission 

limits for all new coal-fired EGUs; the 

mercury (Hg) emission limit for the 

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

subcategory;’’ fPM and SO2 emission 

limits for new solid oil-derived fuelfired EGUs; fPM emission limits for new 

continental liquid oil-fired EGUs; and 

most of the emission limits for new 

integrated gasification combined cycle 

(IGCC) units. 

The fPM, HCl, and Hg limits that we 

are finalizing in this action are provided 

in table 1; the alternate limits that we 

are finalizing are provided in table 2.3

TABLE 1—REVISED EMISSION LIMITATIONS FOR NEW EGUS

Subcategory 

Filterable 

particulate 

matter, 

lb/MWh 

Hydrogen 

chloride, 

lb/MWh 

Mercury, lb/GWh 

New—Unit not designed for low rank virgin coal ............................................................... 9.0E–2 .............. 1.0E–2 a ............ 3.0E–3. 

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

New—IGCC ........................................................................................................................ 7.0E–2 b ............

9.0E–2 c ............

2.0E–3 .............. 3.0E–3. 

New—Solid oil-derived ....................................................................................................... 3.0E–2 .............. NR .................... NR. 

New—Liquid oil—continental .............................................................................................. 3.0E–1 .............. NR .................... NR. 

Note: lb/MWh = pounds pollutant per megawatt-hour electric output (gross). 

lb/GWh = pounds pollutant per gigawatt-hour electric output (gross). 

NR = limit not opened for reconsideration (77 FR 9304; February 16, 2012). 

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. 

TABLE 2—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 


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4See ‘‘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 for Final Rule,’’ Docket ID 

EPA–HQ–OAR–2009–0234–20132, p. 13. 

TABLE 2—REVISED ALTERNATE EMISSION LIMITATIONS FOR NEW EGUS—Continued 

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

Beryllium, Be ....................................................................................................................... NR .................... 1.0E–3 lb/GWh NR 

Cadmium, Cd ...................................................................................................................... NR .................... 2.0E–3 lb/GWh NR 

Chromium, Cr ..................................................................................................................... NR .................... 4.0E–2 lb/GWh NR 

Cobalt, Co ........................................................................................................................... NR .................... 4.0E–3 lb/GWh NR 

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

Mercury, Hg ........................................................................................................................ NA ..................... NA .................... NR 

Manganese, Mn .................................................................................................................. NR .................... 2.0E–2 lb/GWh NR 

Nickel, Ni ............................................................................................................................. NR .................... 7.0E–2 lb/GWh NR 

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

NA = not applicable. 

NR = limit not opened for reconsideration (77 FR 9304; February 16, 2012). 

aBased on best-performing similar source. 

bBased on DOE information. 

In addition, in the MATS NESHAP 

the EPA is removing quarterly stack 

testing as an option to demonstrate 

compliance with the new source fPM 

emission limits; revising the way in 

which an owner or operator of a new 

EGU who chooses to use PM continuous 

parameter monitoring systems (CPMS) 

establishes an operating limit; requiring 

inspections and retesting within 45 days 

of an exceedance of the operating limit 

for those new EGU owners or operators 

who choose to use PM CPMS as a 

compliance option; and finalizing the 

presumption of violation of the 

emissions limit if more than 4 emissions 

tests are required in a 12-month period. 

The final changes to the numerical 

emissions limits noted above 

incorporate information about the 

variability of the best performing EGUs 

and more accurately reflect the 

capabilities of emission control 

equipment for new EGUs. The final 

changes should also address 

commenters’ concerns that vendors of 

EGU emission controls had been 

unwilling to provide guarantees 

regarding the ability to meet all of the 

standards for new EGUs as originally 

finalized in February 2012. 

We expect that source owners and 

operators will install and operate the 

same or similar control technologies to 

meet the revised standards in this 

reconsideration action as they would 

have chosen to comply with the 

standards in the February 2012 final 

rule. Consistent with CAA section 

112(a)(4), we are maintaining the new 

source trigger date for the MATS 

NESHAP rule as May 3, 2011. See 77 FR 

71330, fn. 7. New sources must comply 

with the revised MATS emission 

standards described in section IV below 

by April 24, 2013, or startup, whichever 

is later. 

In the February 2012 final Utility 

NSPS rule, the EPA adopted a definition 

of natural gas that excludes coal-derived 

synthetic natural gas consistent with the 

definition in MATS. In the Utility NSPS 

reconsideration proposal, we reproposed and requested comment on 

that definition. Based on review of the 

comments received in response to the 

reconsideration proposal, the EPA has 

concluded that the definition of natural 

gas in the final Utility NSPS is 

appropriate and, therefore, is not 

making any changes to that definition. 

We are also finalizing as proposed one 

conforming amendment and two 

amendments related to EGUs burning 

desulfurized coal-derived synthetic 

natural gas. First, we amended the 

definition of coal to make it clear that 

coal-derived synthetic natural gas is 

considered to be coal. In addition, in 

recognition of the fact that emissions 

from the burning of desulfurized coalderived synthetic natural gas are very 

similar to those from the burning of 

natural gas, we amended the opacity 

and SO2 monitoring provisions so that 

facilities burning desulfurized coalderived synthetic natural gas will have 

opacity and SO2 monitoring 

requirements similar to those of 

facilities burning natural gas. Further, 

we are finalizing certain revisions to the 

definition of IGCC in the Utility NSPS. 

We are also finalizing as proposed the 

revised procedures for calculating PM 

emission rates intended to make the 

Utility NSPS procedures consistent with 

those in the MATS NESHAP. We did 

not receive any adverse comments 

regarding this proposed change. Finally, 

we are finalizing as proposed the 

technical corrections to the PM 

standards for facilities that commenced 

construction before March 1, 2005, and 

for facilities that commence 

modification after May 3, 2011. 

The impacts of today’s revisions on 

the costs and the benefits of the final 

rule are minor. As noted above, we 

expect that source owners and operators 

will install and operate the same or 

similar control technologies to meet the 

revised standards in this action as they 

would have chosen to comply with the 

standards in the February 2012 final 

rule. 

IV. Summary of Final Action and 

Changes Since Proposal—MATS 

NESHAP New Source Issues 

After consideration of the public 

comments received, the EPA has made 

certain changes in this final action from 

the reconsideration proposal. We 

address the most significant comments 

in this preamble. However for a 

complete summary of the comments 

received on the issues we are finalizing 

today and our responses thereto, please 

refer to the memorandum ‘‘National 

Emission Standards For Hazardous Air 

Pollutants From Coal- And Oil-Fired 

Electric Utility Steam Generating 

Units—Reconsideration; Summary Of 

Public Comments And Responses’’ 

(March 2013) in rulemaking docket 

EPA–HQ–OAR–2009–0234. 

In this action, we are finalizing 

certain new source emission limits for 

the MATS NESHAP, as discussed 

below. 

1. Changes to Certain New Source 

MATS NESHAP Limits 

Commenters noted that in two 

instances, Pb emissions from coal-fired 

EGUs and the fPM emissions from 

continental liquid oil-fired EGUs, the 

EPA had proposed new source emission 

limits that were less stringent than those 

in the final MATS NESHAP for the 

respective existing sources. This 

approach was inconsistent with that 

taken in the final MATS NESHAP.4

Although CAA section 112(d)(3) allows 

existing source MACT floor limits to be 

less stringent than new source limits, 

the EPA interprets this provision as 


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5The CAA section 111 standard is based on the 

performance of EGUs with the best performing SO2

controls, a reasonable incremental cost effectiveness 

of less than $1,000 per ton of SO2 controlled, and 

controls that result in minimal secondary 

environmental and energy impacts. 

6The final Utility NSPS limit was not challenged 

and coal-fired EGUs constructed after May 3, 2011, 

must meet that limit. 

7See Docket ID EPA–HQ–OAR–2009–0234– 

20221 and National Emission Standards for 

Hazardous Air Pollutants (NESHAP) Beyond the 

Maximum Achievable Control Technology (MACT) 

Floor (‘Beyond-the-Floor’) Analysis for Revised 

Emission Standards for New Source Coal-and Oilfired Electric Utility Steam Generating Units also in 

the rulemaking docket. 

8The EPA developed the memorandum to 

determine appropriate RDL and 3XRDL values for 

sorbent trap monitoring systems, as well as 

calculate an emissions limit, in order to determine 

the shortest, reasonable sample collection period for 

those systems. See EPA Docket ID EPA–HQ–OAR– 

2009–0234–20222. 

precluding new source limits from being 

less stringent than existing source 

limits. See CAA section 112(d)(3). Thus, 

for Pb emissions from coal-fired EGUs 

and fPM emissions from continental 

liquid oil-fired EGUs, the EPA is 

finalizing new source limits that are 

equivalent to the final existing-source 

limits. 

Next, commenters noted that when 

evaluating SO2 emissions data from 

coal-fired EGUs, the EPA had not 

selected the lowest emitting source 

upon which to base the emission limit 

and that its rationale for excluding 

certain data was unlawful and arbitrary. 

Although the EPA disagrees with 

commenters on several of the excluded 

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

suggested by commenters comprised 

only a single 3-run average for each EGU 

with no individual run data, making 

assessment of variability impossible), it 

agrees that it inadvertently omitted the 

data from Stanton Unit 10 in the 

proposal analyses. Stanton Unit 10 does 

have a lower ‘‘lowest’’ 3-run data 

average than does the EGU selected for 

the new source floor analysis (Sandow 

Unit 5A) in the proposed 

reconsideration rule. 

In this final action, the EPA used the 

Stanton data to calculate the MACT 

floor using the same statistical analyses 

used in the proposed rule (i.e., 99 

percent upper predictive limit (UPL)), 

and the resulting MACT floor emission 

limit is 1.3 pounds per megawatt-hour 

(lb/MWh). Because this limit is less 

stringent than the new source 

performance standard (NSPS) finalized 

in the Utility NSPS (77 FR 9451; 

February 16, 2012), the EPA is finalizing 

a beyond-the-floor (BTF) MACT 

standard of 1.0 lb/MWh, which is the 

same level required by the CAA section 

111 NSPS for these same sources.5 See 

40 CFR 60.43Da(l)(1)(i). Cost is a 

required consideration in establishing 

CAA section 111 rules and in going BTF 

in establishing CAA section 112 rules. 

We evaluated cost in assessing whether 

to go BTF for this standard and 

concluded that it was appropriate to go 

BTF to a level of 1.0 lb/MWh. Moreover, 

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

place and coal-fired EGUs are required 

to comply with that limit. As such, there 

is no additional cost to these sources.6

Furthermore, we have not identified any 

non-air quality health or environmental 

impacts or energy requirements 

associated with the final standard set at 

this level. In addition, in support of the 

proposed reconsideration rule, we 

evaluated an emissions level more 

stringent than 1.0 lb/MWh and found 

that level to not be cost effective.7 For 

these reasons, we are finalizing 1.0 lb/ 

MWh as the new source MATS 

NESHAP limit. 

In the proposed reconsideration rule, 

we indicated that detection level issues 

may arise from using a sorbent trap 

when short sampling periods (e.g., 30 

minutes) are used. As such, the EPA 

solicited comment on its establishment 

of a Representative Detection Level 

(RDL) associated with Hg sorbent traps. 

The EPA also solicited comment on 

whether the UPL calculated floor should 

be compared against the 3XRDL value 

for Hg to account for the shorter 

sampling periods (the 3XRDL 

approach). The EPA received several 

comments, ranging from strong support 

for the Hg RDL and the proposed 

emission limit because, at that level, the 

commenters asserted that vendors 

would be able to provide commercial 

guarantees, to concerns about the 

specific inputs to the 3XRDL calculation 

and the application of the 3xRDL 

approach. See section 2.2.1 of the 

response to comments document (RTC) 

for a more complete discussion and 

response to these comments. 

In the proposed reconsideration rule, 

the EPA recognized that 30 minutes of 

sample collection is the shortest 

reasonable amount of time available for 

collecting and changing sorbent tubes to 

provide the quick, reliable feedback that 

will allow sources to react to changing 

Hg emissions levels and assure 

compliance with the final Hg limit. 

Some commenters pointed out that the 

EPA’s memorandum entitled 

‘‘Determination of Representative 

Detection Level (RDL) and 3 X RDL 

Values for Mercury Measured Using 

Sorbent Trap Technologies,’’ 8 contains 

a 30-minute sample collection time in 

the 3XRDL calculation, but the text of 

the memorandum references a 20- 

minute sample collection time. The EPA 

has revised the text of the memorandum 

to reflect its original intent, which was 

to focus on a sample collection period 

of 30 minutes (not 20 minutes). The 

revised memorandum focuses on the 30- 

minute sample collection period. Given 

that it takes 5 minutes for sorbent trap 

insertion and removal, it would take a 

total of 40 minutes to secure the 

requisite sample collection (30 minutes 

for sample collection, 5 minutes to 

remove the sorbent trap, and 5 minutes 

to re-insert the trap). We are finalizing 

the Hg limit using the 3XRDL approach 

assuming a 30-minute sampling time. 

2. Filterable PM Testing, Monitoring, 

and Compliance 

Certification for New EGUs in the 

MATS NESHAP Rule 

Several monitoring options for the 

fPM standard for new sources were 

provided in the MATS NESHAP final 

rule, including quarterly stack testing, 

PM CEMS, and PM CPMS with annual 

testing. 

The EPA sought comment on whether 

to retain the quarterly stack testing 

compliance option for new EGUs, given 

that continuous, direct measurement of 

fPM or a correlated parameter is 

available, is preferable for determining 

compliance on a continuous basis, and 

is likely to be used by most new EGUs 

to monitor compliance with the 

proposed new source standards. As 

mentioned above, this final action does 

not retain the quarterly fPM 

performance testing option for new 

EGUs. New EGUs can be designed to 

incorporate PM CEMS or PM CPMS 

from the outset, without being impeded 

by retrofit location installation 

constraints that could impact existing 

EGUs. This final action now requires 

new sources to use either PM CEMS or 

PM CPMS as options for determining 

compliance with the new source fPM 

limits. 

The EPA requested comment on a 

number of issues associated with PM 

CPMS. The EPA first solicited comment 

on three approaches to establish an 

operating limit based on emissions 

testing for those EGU owners or 

operators who choose to use PM CPMS 

as the means of demonstrating 

compliance with the fPM emission 

limit. The first approach would require 

an EGU owner or operator to use the 

highest parameter value obtained during 

any run of an individual emissions test 

as the operating limit when the result of 

that individual test was below the limit. 

The second approach would require an 

EGU owner or operator to use the 

average parameter value obtained from 


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24078 Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 

9See Standards of Performance for New 

Stationary Sources and Emission Guidelines for 

Existing Sources: Commercial and Industrial Solid 

Waste Incineration Units, 76 FR 15736 (March 21, 

2011); Subpart DDDDD—National Emission 

Standards for Hazardous Air Pollutants for Major 

Sources: Industrial, Commercial, and Institutional 

Boilers and Process Heaters, 40 CFR 63.7515(b); and 

National Emission Standards for Hazardous Air 

Pollutants for the Portland Cement Manufacturing 

Industry and Standards of Performance for Portland 

Cement Plants, 78 FR 10014 (February 12, 2013). 

all runs of an individual emissions test 

as the operating limit, provided that the 

result of the individual emissions test 

met the emissions limit. The third 

approach, which the EPA is finalizing in 

this final action, would require an EGU 

owner or operator to use the higher of 

the following: (1) A parameter scaled 

from all values obtained during an 

individual emissions test to 75 percent 

of the emissions limit or (2) the average 

parameter value obtained from all runs 

of an individual emissions test as the 

operating limit provided that the result 

of the individual emissions test met the 

emissions limit. As established and 

reaffirmed in the recent Sewage Sludge 

Incineration, Major Source Industrial 

Boiler, and Portland Cement rules,9 it is 

appropriate to provide increased 

operational flexibility and reduced 

emissions testing for sources that emit at 

or below 75 percent of a standard— 

whether an emissions or operating 

limit—as these are the lowest emitting 

sources. Reduced emissions testing is 

available in this final rule for those 

owners or operators whose EGU 

emissions do not exceed this 75 percent 

threshold. This 75 percent threshold 

allows for compliance flexibility and is 

simultaneously protective of the 

emission standards. The EPA believes 

well performing EGUs, i.e., those whose 

emissions do not exceed 75 percent of 

the emissions limit, should not face 

additional scrutiny or testing 

consequences provided their emissions 

remain equivalent to or below the 75 

percent threshold. In this final action, 

the EPA uses the 75 percent threshold 

so as not to impose unintended and 

costly retest requirements for the lowest 

emitting sources and to provide for 

more cost effective, continuous, PM 

parametric monitoring across the EGU 

sector. This approach was selected from 

the options considered as it provides the 

greatest amount of EGU owner or 

operator flexibility while demonstrating 

continuous compliance for EGUs. With 

this parametric monitoring approach in 

place, the EPA expects EGUs to evaluate 

control options that provide excellent 

fPM emissions control and provide 

them greater operational flexibility. 

Moreover, after each exceedance of 

the operating limit, the EPA proposed to 

require emissions testing to verify or readjust the operating limit, consistent 

with the approach contained in the 

recently-promulgated Portland cement 

MACT standard (see 78 FR 10014). One 

commenter objected to potential 

frequent emissions testing to reassess 

the operating limit and then being 

subject to a violation of the emissions 

limit. The EPA does not believe that toofrequent testing will be required. As 

discussed in section 4.3.5 of the RTC, 

the EPA believes well-designed 

emissions testing will provide an 

operating limit corresponding with EGU 

operation, and such testing should yield 

an operating limit that would not be 

expected to be exceeded during the 

course of EGU operation. Therefore, an 

operating limit developed from welldesigned emissions testing should have 

little, if any, need for frequent 

reassessment via emissions testing more 

frequently than the mandated annual 

reassessment because the source will be 

able to meet the limit on an ongoing 

basis. 

Finally, the EPA proposed that PM 

CPMS exceedances leading to more than 

4 required emissions tests in a 12-month 

period (rolling monthly) would be 

presumed (subject to the possibility of 

rebuttal by the EGU owner or operator) 

to be a violation of the emissions limit, 

consistent with the approach contained 

in the newly-promulgated Portland 

cement MACT standard (see 78 FR 

10014). The EPA received a number of 

comments on this proposed provision, 

including comments supporting and 

opposing the establishment of such a 

presumption. 

The EPA disagrees with those 

comments opposing the presumptive 

violation, and believes the presumptive 

violation provision in the final rule is a 

reasonable and appropriate approach to 

ensure compliance with the standard. 

First, the EPA may permissibly establish 

such an approach by rule, assuming 

there is a reasonable factual basis to do 

so. See Hazardous Waste Treatment 

Council v. EPA, 886 F. 2d 355, 367–68 

(DC Cir. 1989) (explaining that such 

presumptions can legitimately establish 

the elements of the EPA’s prima facie 

case in an enforcement action). Second, 

there is a reasonable basis here for the 

presumption that four exceedances (i.e., 

increases over the parametric operating 

limit) in a calendar year are a violation 

of the emission standard. The 

parametric monitoring limit is 

established as a 30-day average of the 

averaged test value in the performance 

test, or the 75th percentile value if that 

is higher. In either instance, the 30-day 

averaging feature provides significant 

leeway to the EGU owner or operator 

not to deviate from the parametric 

operating level because the impact of 

transient peaks or valleys is limited due 

to the length of the rule’s averaging 

period—30 boiler operating days, rolled 

daily. See 77 FR 42377/2 and sources 

there cited. See also 78 FR 10015, 

10019; February, 12, 2013 (Portland 

Cement MACT) and the RTC for today’s 

action. 

The EPA also received comments 

addressing the re-testing requirements 

following an exceedance. Some 

commenters expressed concern about 

the burden of requiring sources to 

conduct performance tests in order to 

demonstrate compliance and to reassess 

the parameter level. In contrast, other 

commenters supported a requirement to 

require re-testing but claimed that the 

time period between observing a 

parameter exceedance and retesting is 

too long. The EPA believes that the retesting requirements are reasonable and 

appropriate to identify non-compliance 

without imposing undue burden. For 

even a single exceedance to occur, the 

30-day average would have to be higher 

than the operating limit established for 

the PM CPMS during normal EGU 

operation. If that occurs, then the EGU 

owner or operator is required to conduct 

an inspection to determine any 

abnormalities and an emissions test to 

re-establish or generate a new operating 

limit. Given that EGUs and their 

emissions control devices are designed 

to operate at known, specific conditions, 

deviations from these conditions are not 

expected and are indicative of problems 

with load, controls, or some 

combination of both. Where these sorts 

of problems result in an exceedance of 

the source’s operating limit, it is 

reasonable to require re-testing in order 

to identify and then correct problems. 

More than four such exceedances of the 

30-day average would mean that the 

EGU owner or operator was unable to 

determine or correct the problem, since 

inspection and re-calculation of the 

operating limit is required after each 

exceedance. This indicates an ongoing 

problem with maintaining process 

control and/or control device operation, 

which would be the basis for a 

presumptive violation of the emissions 

standard. Moreover, the EPA disagrees 

that the period between exceedance of 

the operating limit and retesting is too 

long and could result in possible 

excessive emissions. Specifically, some 

commenters claimed that the final rule 

should not limit the number of 

exceedances of the PM CPMS limit that 

require follow-up performance tests in 

any 12-month period. These 

commenters alleged that to do so does 


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Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 24079 

not ensure continuous compliance 

because the time period between an 

exceedance and testing could be too 

long, and a source could be exceeding 

the emission limit during that time 

period. The EPA believes that the retesting requirements reflect a reasonable 

balance between ensuring compliance 

and limiting unnecessary testing burden 

on regulated sources. An EGU owner or 

operator is required to visually inspect 

the air pollution control device within 

48 hours of the exceedance, and 

corrective action must be taken as soon 

as possible to return the PM CPMS 

measurement to within the established 

value. A performance test is also 

required within 45 days of the 

exceedance to determine compliance 

and verify or re-establish the PM CPMS 

limit. Thus, the EPA finds it unlikely 

that there will be long periods of 

noncompliance with the underlying 

fPM standard given the inspection and 

performance testing requirements. 

The EPA also received comments 

stating that an EGU owner or operator 

should not be labeled a ‘‘violator’’ of the 

fPM standard as a result of a fourth 

compliance test in a 12-month period. 

First, the EPA notes that the rule 

identifies more than 4 compliance tests 

over a 12-month period as only a 

presumptive violation of the emissions 

limit. A presumption of a violation is 

just that—a presumption—and can be 

rebutted in any particular case. 

Moreover, in determining whether the 

presumption has been successfully 

rebutted, a Court may consider relevant 

information such as data or other 

information showing that the EGU’s 

operating process remained in control 

during the period of operating 

parameter exceedance, that the ongoing 

operation and maintenance conducted 

on the EGU ensured its emissions 

control devices remained in proper 

operating condition during the period of 

operating parameter exceedance, and 

that results of emissions tests conducted 

while replicating the conditions 

observed during the period of operating 

parameter exceedance remained below 

the emission limit. 

For the reasons explained above, this 

final action includes the presumption of 

violation of the emissions limit if more 

than 4 emissions tests are required in a 

12-month period. 

V. Summary of Final Action and 

Changes Since Proposal—Utility NSPS 

The EPA has made a number of 

changes from the reconsideration 

proposal in this final action after 

consideration of the public comments 

received. Most of the changes to the 

Utility NSPS clarify applicability and 

implementation issues raised by the 

commenters. The public comments 

received on the matters proposed for 

reconsideration and the responses to 

them can be viewed in the 

memorandum ‘‘Summary of EGU NSPS 

Public Comments and Responses on 

Amendments Proposed November 30, 

2012 (77 FR 71323)’’ in rulemaking 

docket EPA–HQ–OAR–2011–0044. 

In the proposed reconsideration rule, 

the EPA proposed a new definition for 

IGCC which would be consistent with 

the MATS NESHAP definition. 

However, as an alternative we requested 

comment on whether to retain a 

definition similar, but not identical, to 

the IGCC definition in the February 

2012 final Utility NSPS. We have 

concluded that the alternative approach 

is most appropriate and are adopting a 

slightly revised definition that is 

consistent with the Agency’s statements 

on IGCC contained in the RTC in 

support of the final Utility NSPS rule 

published on February 16, 2012 (77 FR 

9304). Commenters generally supported 

amending the final Utility NSPS 

definition of IGCC, and this final action 

amends that definition consistent with 

the statements made in the RTC for the 

Utility NSPS. The Utility NSPS IGCC 

definition deals with the intent of an 

IGCC facility and is, thus, broader than 

the definition in the MATS NESHAP. 

The facility would still be subject to the 

same criteria pollutant emission 

standards even when burning natural 

gas for extended periods of time. The 

MATS NESHAP applicability is 

determined based on the EGU’s 

utilization of coal and oil and the rule 

may not apply depending on the extent 

of natural gas usage. 

The EPA proposed that the NSPS PM 

monitoring procedures be consistent 

with the MATS NESHAP requirements 

and included the use of quarterly stack 

testing, PM CPMS, or PM CEMS. In 

addition, the EPA sought comment on 

whether to include the quarterly stack 

testing compliance option for new 

EGUs, given that continuous, direct 

measurement of PM or a correlated 

parameter is available. EGUs complying 

with an output-based emissions 

standard can be designed to incorporate 

PM CEMS or PM CPMS from the outset, 

without being impeded by retrofit 

location installation constraints that 

would impact existing EGUs. This final 

action requires EGUs complying with an 

output-based standard to use either PM 

CEMS or PM CPMS as options for 

determining compliance with the PM 

limits. Therefore, the EPA is finalizing 

the same monitoring procedures for PM 

for the Utility NSPS as for new sources 

subject to the MATS NESHAP, and is 

not finalizing the quarterly stack testing 

option. 

The EPA proposed that facilities using 

PM CPMS would be able to use either 

a continuous opacity monitoring system 

or a periodic alternate monitoring 

approach to monitor opacity. This final 

action does not require facilities using a 

PM CPMS to conduct opacity 

monitoring. The EPA has concluded 

that the use of a PM CPMS at the level 

of the emissions standard required in 

subpart Da is sufficient to demonstrate 

compliance with the opacity standard 

and that additional monitoring is an 

unnecessary burden. 

VI. Technical Corrections and 

Clarifications 

On April 19, 2012 (77 FR 23399), the 

EPA issued a technical corrections 

notice addressing certain corrections to 

the February 16, 2012 (77 FR 9304), 

MATS NESHAP and Utility NSPS. In 

the November 30, 2012, reconsideration 

proposal, we proposed several 

additional technical corrections. 

Specific to the NSPS, we proposed 

correcting the PM standard for facilities 

that commenced construction before 

March 1, 2005, to remove the extra 

significant digit that was inadvertently 

added and to correct the PM standard 

for facilities that commence 

modification after May 3, 2011, to be 

consistent with the original intent as 

expressed in the RTC of the final rule 

published on February 16, 2012 (77 FR 

9304). We did not receive any negative 

comments on these issues and are 

finalizing them as proposed. Specific 

details are included in Table 3. 

Specific to the MATS NESHAP, the 

EPA requested comment on whether the 

proposed technical corrections in Table 

4 of the preamble provide the intended 

accuracy, clarity, and consistency. As 

mentioned in section 6.3 of the RTC, 

commenters supported the proposed 

changes on equations 2a and 3a and this 

final action contains those changes. As 

mentioned in section 6.3 of the RTC, 

commenters did not support the change 

from a 30 to 60-day notification period 

for performance testing, and that change 

was not made to the rule; however, a 

change to the General Provisions 

applicability table was made to provide 

a consistent 30-day notification period. 

Commenters suggested changes to 

certain definitions to make them more 

consistent with the Acid Rain rule 

provisions, but, as described in section 

6.4 of the RTC, these rule changes were 

not made. These amendments are now 

being finalized to correct inaccuracies 

and other inadvertent errors in the final 

rule and to make the rule language 


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24080 Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 

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 Economic Impact Analysis for the Final 

Reconsideration of the Mercury and Air Toxics 

Standards in rulemaking docket EPA–HQ–OAR– 

2009–0234. As noted earlier, because on an 

individual EGU-by-EGU basis we anticipate very 

similar costs, any changes to the baseline since we 

finalized MATS (e.g., potential impacts of the 

CSAPR decision) would not impact this 

determination. 

consistent with provisions addressed 

through this reconsideration. 

The final technical changes are 

described in tables 3 and 4 of this 

preamble. 

TABLE 3—MISCELLANEOUS TECHNICAL CORRECTIONS TO 40 CFR PART 60, SUBPART DA

Section of subpart Da Description of correction 

40 CFR 60.42Da(a) ........................ Correct the erroneous ‘‘0.030’’ to the correct ‘‘0.03’’. 

40 CFR 60.42Da(e)(1)(ii) ................ Correct the erroneous conversion ‘‘13 ng/J (0.015 lb/MMBtu)’’ to the correct ‘‘6.4 ng/J (0.015 lb/MMBtu)’’ 

by amending the regulatory text to specify that the requirements in 40 CFR 60.42Da(c) or (d), which includes two additional alternative limits, are available compliance alternatives for modified facilities. 

TABLE 4—MISCELLANEOUS TECHNICAL CORRECTIONS TO 40 CFR PART 63, SUBPART UUUUU 

Section of subpart UUUUU Description of correction 

40 CFR 63.9982(a) ......................... Clarify the language to use the word ‘‘or’’ instead of ‘‘and.’’ 

40 CFR 63.9982(b) and (c) ............ Correct the discrepancy between 63.9982(b) and (c) and 63.9985(a). 

40 CFR 63.10005(d)(2)(ii) ............... Correct the typographical error by replacing the incorrect ‘‘corresponding’’ with the correct ‘‘corresponds.’’ 

40 CFR 63.10005(i)(4)(ii) and (i)(5) 

and add 63.10005(i)(6).

Revise to clarify the determination and measurement of fuel moisture content. 

40 CFR 63.10006(c) ....................... Correct the omission of solid oil-derived fuel- and coal-fired EGUs and IGCC EGUs and the omission of 

section 10000(c). 

40 CFR 63.10007(c) ....................... Correct the omission of section 63.10023 from the list of sections to be followed in establishing an operating limit. 

40 CFR 63.10009(b)(2) ................... Correct omission of the term ‘‘boiler operating’’ and clarify the term ‘‘Rti’’ in Equation 2a. 

40 CFR 63.10009(b)(3) ................... Correct omission of the term ‘‘system’’ and clarify the term ‘‘Rti’’ in Equation 3a. 

40 CFR 63.10010(j)(1)(i) ................. Correct the typographical error to use the correct word ‘‘your’’ instead of ‘‘you.’’ 

40 CFR 63.10030(b), (c), and (d) ... Clarify the affected-source language. 

Change the period by which a Notification of Intent to conduct a performance test must be submitted to 

conform to the General Provisions. 

40 CFR Section 63.10042 .............. Correct the typographical error in the intended definition of ‘‘unit designed for coal ≥ 8,300 Btu/lb subcategory’’ by replacing the erroneous ‘‘>’’ with the correct ‘‘≥.’’ 

Table 5 to Subpart UUUUU of Part 

63.

Correct the typographical error in footnote 4 by replacing the erroneous ‘‘≥’’ with the correct ‘‘≤.’’ 

Table 7 to Subpart UUUUU of Part 

63.

Clarify the applicability of the alternate 90-day average for Hg in item 1. 

Revise item 3 in the table to clarify use of CMS for liquid oil-fired EGUs. 

Table 9 to Subpart UUUUU of Part 

63.

Revise to clarify the period for notification of conducting a performance test from 60 to 30 days. 

Section 4.1 to Appendix A to Subpart UUUUU of Part 63.Correct the typographical error by replacing the incorrect citation to ‘‘§ 63.10005(g)’’ with the correct 

‘‘§ 63.9984(f).’’ 

Section 5.2.2.2 to Appendix A to 

Subpart UUUUU of Part 63.

Correct the typographical error by replacing the incorrect citation to ‘‘Table A–4’’ with the correct ‘‘Table A– 

2’’ 

Section 3.1.2.1.3 to Appendix B to 

Subpart UUUUU of Part 63.

Correct the typographical error by replacing the erroneous ‘‘≥’’ with the correct ‘‘≤.’’ 

Section 5.3.4 to Appendix B to 

Subpart UUUUU of Part 63.

Correct the section number from the incorrect ‘‘5.3.4’’ to the correct ‘‘5.3.3.’’ 

VII. Impacts of This Final Rule 

A. Summary of Emissions Impacts, 

Costs and Benefits 

Our analysis shows that new EGUs 

would choose to install and operate the 

same or similar air pollution control 

technologies in order to meet the 

revised emission limits as would have 

been necessary to meet the previously 

finalized standards. We project that this 

final action will result in no significant 

change in costs, emission reductions, or 

benefits.10 Even if there were changes in 

costs for these EGUs, such changes 

would likely be small relative to both 

the overall costs of the individual 

projects and the overall costs and 

benefits of the final rule. Further, we 

believe that EGUs would put on the 

same controls for this final action that 

they would have for the original final 

MATS rule, so there should not be any 

incremental costs related to this 

revision. 

B. What are the air impacts? 

We believe that electric power 

companies will install the same or 

similar control technologies to comply 

with the final standards in this action as 

they would have installed to comply 

with the previously finalized MATS 

standards. Accordingly, we believe that 

this final action will not result in 

significant changes in emissions of any 

of the regulated pollutants. 

C. What are the energy impacts? 

This final action is not anticipated to 

have an effect on the supply, 

distribution, or use of energy. As 

previously stated, we believe that 

electric power companies would install 

the same or similar control technologies 

as they would have installed to comply 

with the previously finalized MATS 

standards. 

D. What are the compliance costs? 

We believe there will be no significant 

change in compliance costs as a result 

of this final action because electric 


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Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 24081 

power companies would install the 

same or similar control technologies as 

they would have installed to comply 

with the previously finalized MATS 

standards. Moreover, we find no 

additional monitoring costs are 

necessary to comply with this final 

action; however, as in any other rule, 

EGU owners or operators may choose to 

conduct additional monitoring (and 

incur its expense) for their own 

purposes. 

E. What are the economic and 

employment impacts? 

Because we expect that electric power 

companies would install the same or 

similar control technologies to meet the 

standards finalized in this action as they 

would have chosen to comply with the 

previously finalized MATS standards, 

we do not anticipate that this final 

action will result in significant changes 

in emissions, energy impacts, costs, 

benefits, or economic impacts. Likewise, 

we believe this action will not have any 

impacts on the price of electricity, 

employment or labor markets, or the 

U.S. economy. 

F. What are the benefits of the final 

standards? 

As previously stated, the EPA 

anticipates the power sector will not 

incur significant compliance costs or 

savings as a result of this action and we 

do not anticipate any significant 

emission changes resulting from this 

action. Therefore, there are no direct 

monetized benefits or disbenefits 

associated with this action. 

VIII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

Under Executive Order (EO) 12866 

(58 FR 51735; October 4, 1993), this 

action is a ‘‘significant regulatory 

action’’ because it ‘‘raises novel legal or 

policy issues.’’ Accordingly, the EPA 

submitted this action to the Office of 

Management and Budget (OMB) for 

review under Executive Orders 12866 

and 13563 (76 FR 3821; January 21, 

2011) and any changes made in 

response to OMB recommendations 

have been documented in the docket for 

this action. 

In addition, the EPA prepared an 

analysis of the potential costs and 

benefits associated with this action. 

This analysis is contained in the 

‘‘Economic Impact Analysis for the 

Final Reconsideration of the Mercury 

and Air Toxics Standards’’ found in 

rulemaking docket EPA–HQ–OAR– 

2009–0234. Because our analysis shows 

that new electricity generating units 

would choose to install the same control 

technology in order to meet the revised 

emission limits as would have been 

necessary to meet the previously 

finalized MATS standards, we project 

that this action will result in no 

significant change in costs, emission 

reductions, or benefits. 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden. Today’s 

action does not change the information 

collection requirements previously 

finalized and, as a result, does not 

impose any additional burden on 

industry. However, OMB has previously 

approved the information collection 

requirements contained in the existing 

regulations (see 77 FR 9304) under the 

provisions of the Paperwork Reduction 

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

assigned OMB control number 2060– 

0567. The OMB control numbers for 

EPA’s regulations are listed in 40 CFR 

part 9 and 48 CFR chapter 15. 

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 action on small entities, a 

small entity is defined as: (1) A small 

business as defined by the Small 

Business Administration’s (SBA) 

regulations at 13 CFR 121.201; (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district, or special district with a 

population of less that 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. Categories and 

entities potentially regulated by the 

final rule with applicable NAICS codes 

are provided in the Supplementary 

Information section of this action. 

According to the SBA size standards 

for NAICS code 221122 Utilities-Fossil 

Fuel Electric Power Generation, a firm 

is small if, including its affiliates, it is 

primarily engaged in the generation, 

transmission, and or distribution of 

electric energy for sale and its total 

electric output for the preceding fiscal 

year did not exceed 4 million MWh. 

After considering the economic 

impacts of today’s action on small 

entities, I certify that the notice will not 

have a significant economic impact on 

a substantial number of small entities. 

The EPA has determined that none of 

the small entities will experience a 

significant impact because the action 

imposes no additional regulatory 

requirements on owners or operators of 

affected sources. We have therefore 

concluded that today’s action will not 

result in a significant economic impact 

on a substantial number of small 

entities. 

D. Unfunded Mandates Reform Act 

This action contains no Federal 

mandates under the provisions of Title 

II of the Unfunded Mandates Reform 

Act of 1995 (UMRA), 2 U.S.C. 1531– 

1538 for State, local, or tribal 

governments or the private sector. The 

action imposes no enforceable duty on 

any State, local, or tribal governments or 

the private sector. Therefore, this action 

is not subject to the requirements of 

UMRA sections 202 or 205. 

This action is also not subject to the 

requirements of UMRA section 203 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments 

because it contains no requirements that 

apply to such governments or impose 

obligations upon them. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in EO 

13132. None of the affected facilities are 

owned or operated by state 

governments, and the requirements 

discussed in today’s notice will not 

supersede state regulations that are 

more stringent. Thus, EO 13132 does 

not apply to today’s notice of 

reconsideration. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications. It will not have substantial 

direct effects on tribal governments, on 

the relationship between the Federal 

government and Indian tribes, or on the 

distribution of power and 

responsibilities between the Federal 

government and Indian tribes, as 

specified in EO 13175. No affected 


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24082 Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 

facilities are owned or operated by 

Indian tribal governments. Thus, EO 

13175 does not apply to today’s action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

This action is not subject to EO 13045 

(62 FR 19885; April 23, 1997) because 

it is not economically significant as 

defined in EO 12866. The EPA has 

evaluated the environmental health or 

safety effects of the final MATS on 

children. The results of the evaluation 

are discussed in that final rule (77 FR 

9304; February 16, 2012) and are 

contained in rulemaking docket EPA– 

HQ–OAR–2009–0234. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not a ‘‘significant 

energy action’’ as defined in EO 13211 

(66 FR 28355; May 22, 2001) because it 

is not likely to have a significant 

adverse effect on the supply, 

distribution, or use of energy. Further, 

we conclude that today’s action is not 

likely to have any adverse energy effects 

because it is not expected to impose any 

additional regulatory requirements on 

the owners of affected facilities. 

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 

MATS rule, the EPA searched for 

voluntary consensus standards that 

might be applicable. The search 

identified three voluntary consensus 

standards that were considered practical 

alternatives to the specified EPA test 

methods. An assessment of these and 

other voluntary consensus standards is 

presented in the preamble to the final 

MATS rule (77 FR 9441; February 16, 

2012). Today’s action does not make use 

of any additional technical standards 

beyond those cited in the final MATS 

rule. Therefore, the EPA is not 

considering the use of any additional 

voluntary consensus standards for this 

action. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-income Populations 

Executive Order 12898 (59 FR 7629; 

February 16, 1994) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

The EPA has determined that this 

action will not have disproportionately 

high and adverse human health or 

environmental effects on minority or 

low-income populations because it does 

not affect the level of protection 

provided to human health or the 

environment. Our analysis shows that 

new EGUs would choose to install the 

same control technology in order to 

meet the revised emission limits as 

would have been necessary to meet the 

previously finalized standard. Under the 

relevant assumptions, we project that 

this action will result in no significant 

change in emission reductions. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. The EPA will 

submit a report containing this final 

action and other required information to 

the U.S. Senate, the U.S. House of 

Representatives, and the Comptroller 

General of the United States prior to 

publication of the rule in the Federal 

Register. A major rule cannot take effect 

until 60 days after it is published in the 

Federal Register. This action is not a 

‘‘major rule’’ as defined by 5 U.S.C. 

804(2). This rule will be effective April 

24, 2013. 

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: March 28, 2013. 

Bob Perciasepe, 

Acting Administrator. 

For the reasons discussed in the 

preamble, 40 CFR parts 60 and 63 are 

amended to read as follows: 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

■ 1. The authority citation for part 60 

continues to read as follows: 

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

■ 2. Amend § 60.41Da by revising the 

definitions of ‘‘Coal’’ and ‘‘Integrated 

gasification combined cycle electric 

utility steam generating unit,’’ and by 

adding the definition of ‘‘Natural gas’’ in 

alphabetical order to read as follows: 

§ 60.41Da Definitions. 

* * * * * 

Coal means all solid fuels classified as 

anthracite, bituminous, subbituminous, 

or lignite by the American Society of 

Testing and Materials in ASTM D388 

(incorporated by reference, see § 60.17) 

and coal refuse. Synthetic fuels derived 

from coal for the purpose of creating 

useful heat, including but not limited to 

solvent-refined coal, gasified coal, 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 is 

designed to burn fuels containing 50 

percent (by heat input) or more solidderived fuel not meeting the definition 

of natural gas. The Administrator may 

waive the 50 percent solid-derived fuel 

requirement during periods of the 

gasification system construction, startup 

and commissioning, shutdown, or 

repair. No solid fuel is directly burned 

in the unit during operation. 

* * * * * 

Natural gas means a fluid mixture of 

hydrocarbons (e.g., methane, ethane, or 

propane), composed of at least 70 

percent methane by volume or that has 

a gross calorific value between 35 and 

41 megajoules (MJ) per dry standard 

cubic meter (950 and 1,100 Btu per dry 

standard cubic foot), that maintains a 

gaseous state under ISO conditions. In 

addition, natural gas contains 20.0 

grains or less of total sulfur per 100 

standard cubic feet. Finally, natural gas 


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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), and (e)(1) to read 

as follows: 

§ 60.42Da Standards for particulate matter 

(PM). 

(a) Except as provided in paragraph (f) 

of this section, on and after the date on 

which the initial performance test is 

completed or required to be completed 

under § 60.8, whichever date comes 

first, an owner or operator of an affected 

facility shall not cause to be discharged 

into the atmosphere from any affected 

facility for which construction, 

reconstruction, or modification 

commenced before March 1, 2005, any 

gases that contain PM in excess of 13 

ng/J (0.03 lb/MMBtu) heat input. 

(b) * * * 

(2) An owner or operator of an 

affected facility that combusts only 

natural gas and/or synthetic natural gas 

that chemically meets the definition of 

natural gas is exempt from the opacity 

standard specified in paragraph (b) of 

this section. 

* * * * * 

(e) * * * 

(1) On and after the date on which the 

initial performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, the owner 

or operator shall not cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain PM in excess of the applicable 

emissions limit specified in paragraphs 

(e)(1)(i) or (ii) of this section. 

(i) For an affected facility which 

commenced construction or 

reconstruction: 

(A) 11 ng/J (0.090 lb/MWh) gross 

energy output; or 

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

output. 

* * * * * 

(ii) For an affected facility which 

commenced modification, the emission 

limits specified in paragraphs (c) or (d) 

of this section. 

* * * * * 

■ 4. Amend § 60.48Da by revising 

paragraphs (f), (o) introductory text, 

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

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

introductory text to read as follows: 

§ 60.48Da Compliance provisions. 

* * * * * 

(f) For affected facilities for which 

construction, modification, or 

reconstruction commenced before May 

4, 2011, compliance with the applicable 

daily average PM emissions limit is 

determined by calculating the 

arithmetic average of all hourly 

emission rates each boiler operating 

day, except for data obtained during 

startup, shutdown, or malfunction 

periods. Daily averages must be 

calculated for boiler operating days that 

have out-of-control periods totaling no 

more than 6 hours of unit operation 

during which the standard applies. For 

affected facilities for which construction 

or reconstruction commenced after May 

3, 2011, that elect to demonstrate 

compliance using PM CEMS, 

compliance with the applicable PM 

emissions limit in § 60.42Da is 

determined on a 30-boiler operating day 

rolling average basis by calculating the 

arithmetic average of all hourly PM 

emission rates for the 30 successive 

boiler operating days, except for data 

obtained during periods of startup or 

shutdown. 

* * * * * 

(o) Compliance provisions for sources 

subject to § 60.42Da(c)(2), (d), or 

(e)(1)(ii). Except as provided for in 

paragraph (p) of this section, the owner 

or operator must demonstrate 

compliance with each applicable 

emissions limit according to the 

requirements in paragraphs (o)(1) 

through (o)(5) of this section. 

(1) You must conduct a performance 

test to demonstrate initial compliance 

with the applicable PM emissions limit 

in § 60.42Da by the applicable date 

specified in § 60.8(a). Thereafter, you 

must 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; 

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

■ c. Revising paragraphs (a)(4), (b) 

introductory text, and (t). 

The revised and added text reads as 

follows: 

§ 60.49Da Emission monitoring. 

(a) An owner or operator of an 

affected facility subject to the opacity 

standard in § 60.42Da must monitor the 

opacity of emissions discharged from 

the affected facility to the atmosphere 

according to the applicable 

requirements in paragraphs (a)(1) 

through (4) of this section. 

* * * * * 

(3) * * * 

(iv) If the maximum 6-minute opacity 

is less than 10 percent during the most 

recent Method 9 of appendix A–4 of this 

part performance test, the owner or 

operator may, as an alternative to 


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24084 Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 

performing subsequent Method 9 of 

appendix A–4 performance tests, elect 

to perform subsequent monitoring using 

a digital opacity compliance system 

according to a site-specific monitoring 

plan approved by the Administrator. 

The observations must be similar, but 

not necessarily identical, to the 

requirements in paragraph (a)(3)(iii) of 

this section. For reference purposes in 

preparing the monitoring plan, see 

OAQPS ‘‘Determination of Visible 

Emission Opacity from Stationary 

Sources Using Computer-Based 

Photographic Analysis Systems.’’ This 

document is available from the U.S. 

Environmental Protection Agency (U.S. 

EPA); Office of Air Quality and 

Planning Standards; Sector Policies and 

Programs Division; Measurement Policy 

Group (D243–02), Research Triangle 

Park, NC 27711. This document is also 

available on the Technology Transfer 

Network (TTN) under Emission 

Measurement Center Preliminary 

Methods. 

* * * * * 

(4) An owner or operator of an 

affected facility that is subject to an 

opacity standard under § 60.42Da is not 

required to operate a COMS provided 

that affected facility meets the 

conditions in either paragraph (a)(4)(i) 

or (ii) of this section. 

(i) The affected facility combusts only 

gaseous and/or liquid fuels (excluding 

residue oil) where the potential SO2

emissions rate of each fuel is no greater 

than 26 ng/J (0.060 lb/MMBtu), and the 

unit operates according to a written 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 deviations with the excess 

emissions report required under 

§ 60.51Da(d). 

(ii) The owner or operator of the 

affected facility installs, calibrates, 

operates, and maintains a particulate 

matter continuous parametric 

monitoring system (PM CPMS) 

according to the requirements specified 

in subpart UUUUU of part 63. 

* * * * * 

(b) The owner or operator of an 

affected facility must install, calibrate, 

maintain, and operate a CEMS, and 

record the output of the system, for 

measuring SO2 emissions, except where 

only gaseous and/or liquid fuels 

(excluding residual oil) where the 

potential SO2 emissions rate of each fuel 

is 26 ng/J (0.060 lb/MMBtu) or less are 

combusted, as follows: 

* * * * * 

(t) The owner or operator of an 

affected facility demonstrating 

compliance with the output-based 

emissions limit under § 60.42Da must 

either install, certify, operate, and 

maintain a CEMS for measuring PM 

emissions according to the requirements 

of paragraph (v) of this section or install, 

calibrate, operate, and maintain a PM 

CPMS according to the requirements for 

new facilities specified in subpart 

UUUUU of part 63 of this chapter. An 

owner or operator of an affected facility 

demonstrating compliance with the 

input-based emissions limit in 

§ 60.42Da may install, certify, operate, 

and maintain a CEMS for measuring PM 

emissions according to the requirements 

of paragraph (v) of this section. 

* * * * * 

■ 6. Revise § 60.50Da(f) to read as 

follows: 

§ 60.50Da Compliance determination 

procedures and methods. 

* * * * * 

(f) The owner or operator of an 

electric utility combined cycle gas 

turbine that does not meet the definition 

of an IGCC must conduct performance 

tests for PM, SO2, and NOX using the 

procedures of Method 19 of appendix 

A–7 of this part. The SO2 and NOX

emission rates calculations from the gas 

turbine used in Method 19 of appendix 

A–7 of this part are determined when 

the gas turbine is performance tested 

under subpart GG of this part. The 

potential uncontrolled PM emission rate 

from a gas turbine is defined as 17 ng/ 

J (0.04 lb/MMBtu) heat input. 

* * * * * 

PART 63—NATIONAL EMISSION 

STANDARDS FOR HAZARDOUS AIR 

POLLUTANTS FOR SOURCE 

CATEGORIES 

■ 7. The authority citation for 40 CFR 

Part 63 continues to read as follows: 

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

■ 8. In § 63.9982, revise paragraphs (a) 

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

follows: 

§ 63.9982 What is the affected source of 

this subpart? 

(a) This subpart applies to each 

individual or group of two or more new, 

reconstructed, or existing affected 

source(s) as described in paragraphs 

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

contiguous area and under common 

control. 

* * * * * 

(b) An EGU is new if you commence 

construction of the coal- or oil-fired 

EGU after May 3, 2011. 

(c) An EGU is reconstructed if you 

meet the reconstruction criteria as 

defined in § 63.2, and if you commence 

reconstruction after May 3, 2011. 

* * * * * 

■ 9. In § 63.10000, revise paragraphs 

(c)(1)(iv) and (c)(2)(ii) to read as follows: 

§ 63.10000 What are my general 

requirements for complying with this 

subpart? 

* * * * * 

(c) * * * 

(1) * * * 

(iv) If your coal-fired or solid oil 

derived fuel-fired EGU or IGCC EGU 

does not qualify as a LEE for total nonmercury HAP metals, individual nonmercury HAP metals, or filterable 

particulate matter (PM), you must 

demonstrate compliance through an 

initial performance test and you must 

monitor continuous performance 

through either use of a particulate 

matter continuous parametric 

monitoring system (PM CPMS), a PM 

CEMS, or, for an existing EGU, 

compliance performance testing 

repeated quarterly. 

* * * * * 

(c) * * * 

(2) * * * 

(ii) If your liquid oil-fired unit does 

not qualify as a LEE for total HAP 

metals (including mercury), individual 

metals (including mercury), or filterable 

PM you must demonstrate compliance 

through an initial performance test and 

you must monitor continuous 

performance through either use of a PM 

CPMS, a PM CEMS, or, for an existing 

EGU, performance testing conducted 

quarterly. 

* * * * * 

■ 10. Amend § 63.10005 by: 

■ a. Revising paragraphs (d)(2)(ii), 

(i)(4)(ii) and (i)(5); 

■ b. Adding paragraph (i)(6). 

The revised and added text read as 

follows: 

§ 63.10005 What are my initial compliance 

requirements and by what date must I 

conduct them? 

* * * * * 

(d) * * * 

(2) * * * 

(ii) You must demonstrate continuous 

compliance with the PM CPMS sitespecific operating limit that corresponds 

to the results of the performance test 


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Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 24085 

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. 

* * * * * 

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

to read as follows: 

§ 63.10006 When must I conduct 

subsequent performance tests or tune-ups? 

* * * * * 

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

of this section apply, or where you 

install, certify, and operate a PM CEMS 

to demonstrate compliance with a 

filterable PM emissions limit, for liquid 

oil-, solid oil-derived fuel-, coal-fired 

and IGCC EGUs, you must conduct all 

applicable periodic emissions tests for 

filterable PM, individual, or total HAP 

metals emissions according to Table 5 to 

this subpart, § 63.10007, and 

§ 63.10000(c), except as otherwise 

provided in § 63.10021(d)(1). 

* * * * * 

■ 12. In § 63.10007, revise paragraph (c) 

to read as follows: 

§ 63.10007 What methods and other 

procedures must I use for the performance 

tests? 

* * * * * 

(c) If you choose the filterable PM 

method to comply with the PM 

emission limit and demonstrate 

continuous performance using a PM 

CPMS as provided for in § 63.10000(c), 

you must also establish an operating 

limit according to § 63.10011(b), 

§ 63.10023, and Tables 4 and 6 to this 

subpart. Should you desire to have 

operating limits that correspond to loads 

other than maximum normal operating 

load, you must conduct testing at those 

other loads to determine the additional 

operating limits. 

* * * * * 

■ 13. In § 63.10009, revise paragraphs 

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

§ 63.10009 May I use emissions averaging 

to comply with this subpart? 

* * * * * 

(b) * * * 

(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, 

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. 


tkelley on DSK3SPTVN1PROD with RULESER24AP13.006</GPH> ER24AP13.007</GPH> ER24AP13.008</GPH>
24086 Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 

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. 

* * * * * 

■ 14. 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. 

* * * * * 

■ 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); 

(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 of the 

operating limit for an EGU subject to the 

emissions limits in Table 1 of this 

subpart leading to more than four 

required performance tests in a 12- 

month period (rolling monthly) 

constitute a separate violation of this 

subpart. 

* * * * * 

■ 16. In § 63.10023, revise paragraph (b) 

to read as follows: 

§ 63.10023 How do I establish my PM 

CPMS operating limit and determine 

compliance with it? 

* * * * * 

(b) Determine your operating limit as 

provided in paragraph (b)(1) or (b)(2) of 

this section. You must verify an existing 

or establish a new operating limit after 

each repeated performance test. 

(1) For an existing EGU, determine 

your operating limit based on the 

highest 1-hour average PM CPMS output 

value recorded during the performance 

test. 

(2) For a new EGU, determine your 

operating limit as follows. 

(i) If your PM performance test 

demonstrates your PM emissions do not 

exceed 75 percent of your emissions 

limit, you will use the average PM 

CPMS value recorded during the PM 

compliance test, the milliamp 

equivalent of zero output from your PM 

CPMS, and the average PM result of 

your compliance test to establish your 

operating limit. Calculate the operating 

limit by establishing a relationship of 

PM CPMS signal to PM concentration 

using the PM CPMS instrument zero, 

the average PM CPMS values 

corresponding to the three compliance 

test runs, and the average PM 

concentration from the Method 5 

compliance test with the procedures in 

(b)(2)(i)(A) through (D) of this section. 

(A) Determine your PM CPMS 

instrument zero output with one of the 

following procedures. 

(1) Zero point data for in-situ 

instruments should be obtained by 

removing the instrument from the stack 

and monitoring ambient air on a test 

bench. 

(2) Zero point data for extractive 

instruments should be obtained by 

removing the extractive probe from the 

stack and drawing in clean ambient air. 

(3) The zero point can also can be 

obtained by performing manual 

reference method measurements when 

the flue gas is free of PM emissions or 

contains very low PM concentrations 

(e.g., when your process is not 

operating, but the fans are operating or 

your source is combusting only natural 

gas) and plotting these with the 

compliance data to find the zero 

intercept. 

(4) If none of the steps in paragraphs 

(A)(1) through (3) of this section are 

possible, you must use a zero output 

value provided by the manufacturer. 

(B) Determine your PM CPMS 

instrument average (x) in milliamps, 

and the average of your corresponding 

three PM compliance test runs (y), using 

equation 10. 


tkelley on DSK3SPTVN1PROD with RULESER24AP13.009</GPH>
Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 24087 

Where: 

Xi = the PM CPMS data points for run i of 

the performance test, 

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

run i of the performance test, and 

n = the number of data points. 

(C) With your PM CPMS instrument 

zero expressed in milliamps, your three 

run average PM CPMS milliamp value, 

and your three run average PM 

emissions value (in lb/MWh) from your 

compliance runs, determine a 

relationship of PM lb/MWh per 

milliamp with equation 11. 

Where: 

R = the relative PM lb/MWh per milliamp for 

your PM CPMS, 

y = the three run average PM lb/MWh, 

x = the three run average milliamp output 

from your PM CPMS, and 

z = the milliamp equivalent of your 

instrument zero determined from 

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

(D) Determine your source specific 30- 

day rolling average operating limit using 

the PM lb/MWh per milliamp value 

from equation 11 in equation 12, below. 

This sets your operating limit at the PM 

CPMS output value corresponding to 75 

percent of your emission limit. 

Where: 

OL = the operating limit for your PM CPMS 

on a 30-day rolling average, in 

milliamps, 

L = your source PM emissions limit in lb/ 

MWh, 

z = your instrument zero in milliamps, 

determined from (b)(2)(i)(A) of this 

section, and 

R = the relative PM lb/MWh per milliamp for 

your PM CPMS, from equation 11. 

(ii) If your PM compliance test 

demonstrates your PM emissions exceed 

75 percent of your emissions limit, you 

will use the average PM CPMS value 

recorded during the PM compliance test 

demonstrating compliance with the PM 

limit to establish your operating limit. 

(A) Determine your operating limit by 

averaging the PM CPMS milliamp 

output corresponding to your three PM 

performance test runs that demonstrate 

compliance with the emission limit 

using equation 13. 

Where: 

Xi = the PM CPMS data points for all runs 

i, 

n = the number of data points, and 

Oh = your site specific operating limit, in 

milliamps. 

(iii) Your PM CPMS must provide a 

4–20 milliamp output and the 

establishment of its relationship to 

manual reference method measurements 

must be determined in units of 

milliamps. 

(iv) Your PM CPMS operating range 

must be capable of reading PM 

concentrations from zero to a level 

equivalent to two times your allowable 

emission limit. If your PM CPMS is an 

auto-ranging instrument capable of 

multiple scales, the primary range of the 

instrument must be capable of reading 

PM concentration from zero to a level 

equivalent to two times your allowable 

emission limit. 

(v) During the initial performance test 

or any such subsequent performance 

test that demonstrates compliance with 

the PM limit, record and average all 

milliamp output values from the PM 

CPMS for the periods corresponding to 

the compliance test runs. 

(vi) For PM performance test reports 

used to set a PM CPMS operating limit, 

the electronic submission of the test 

report must also include the make and 

model of the PM CPMS instrument, 

serial number of the instrument, 

analytical principle of the instrument 

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

instruments primary analytical range, 

milliamp value equivalent to the 

instrument zero output, technique by 

which this zero value was determined, 

and the average milliamp signal 

corresponding to each PM compliance 

test run. 

* * * * * 

■ 17. In § 63.10030, revise paragraphs 

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

§ 63.10030 What notifications must I 

submit and when? 

* * * * * 

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

startup your EGU that is an affected 

source before April 16, 2012, you must 

submit an Initial Notification not later 

than 120 days after April 16, 2012. 

(c) As specified in § 63.9(b)(4) and 

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

reconstructed EGU that is an affected 

source on or after April 16, 2012, you 

must submit an Initial Notification not 

later than 15 days after the actual date 

of startup of the EGU that is an affected 

source. 

(d) When you are required to conduct 

a performance test, you must submit a 

Notification of Intent to conduct a 

performance test at least 30 days before 

the performance test is scheduled to 

begin. 

* * * * * 

■ 18. Amend § 63.10042 by revising the 

definition of ‘‘Unit designed for coal > 

8,300 Btu/lb subcategory’’ to read as 

follows: 

§ 63.10042 What definitions apply to this 

subpart? 

* * * * * 

Unit designed for coal ≥ 8,300 Btu/lb 

subcategory means any coal-fired EGU 

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

designed for low rank virgin coal’’ 

subcategory. 

* * * * * 

■ 19. Revise Table 1 to Subpart UUUUU 

of Part 63 to read as follows: 


tkelley on DSK3SPTVN1PROD with RULESER24AP13.010</GPH> ER24AP13.011</GPH> ER24AP13.012</GPH> ER24AP13.013</GPH>
24088 Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 

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 limit] 

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.

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

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

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

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

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

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

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

For ASTM D6348–03 2 or Method 

320, sample for a minimum of 1 

hour. 

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

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

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

2. Coal-fired units low rank virgin 

coal.

a. Filterable particulate matter 

(PM).

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

run. 

OR OR 

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

run. 

OR OR 

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

run. 

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

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

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

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

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

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

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

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

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

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

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

For ASTM D6348–03 2 or Method 

320, sample for a minimum of 1 

hour. 

OR 

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

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

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

(PM).

7.0E–2 lb/MWh 4 ...........................

9.0E–2 lb/MWh 5 ...........................

Collect a minimum of 1 dscm per 

run. 

OR OR 

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

run. 

OR OR 

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

run. 

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

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

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

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

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


tkelley on DSK3SPTVN1PROD with RULES
Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 24089 

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

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

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 

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 oilfired subcategory units).

a. Filterable particulate matter 

(PM).

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

run. 

OR OR 

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

run. 

OR OR 

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

run. 

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

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

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

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

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

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

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

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

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

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

Mercury (Hg) ................................. 1.0E–4 lb/GWh ............................. For Method 30B sample volume 

determination (Section 8.2.4), 

the estimated Hg concentration 

should nominally be < 1⁄2 the 

standard. 

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

For ASTM D6348–03 2 or Method 

320, sample for a minimum of 1 

hour. 

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

For ASTM D6348–03 2 or Method 

320, sample for a minimum of 1 

hour. 

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

(PM).

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

run. 

OR OR 

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

run. 

OR OR 

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

run. 

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

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

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

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

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

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

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

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


tkelley on DSK3SPTVN1PROD with RULES
24090 Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 

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

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

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 

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

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

Mercury (Hg) ................................. 4.0E–4 lb/GWh ............................. For Method 30B sample volume 

determination (Section 8.2.4), 

the estimated Hg concentration 

should nominally be < 1⁄2 the 

standard. 

b. Hydrogen chloride (HCl) ........... 2.0E–3 lb/MWh ............................. For Method 26A, collect a minimum of 1 dscm per run; for 

Method 26, collect a minimum 

of 120 liters per run. 

For ASTM D6348–03 2 or Method 

320, sample for a minimum of 1 

hour. 

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

For ASTM D6348–03 2 or Method 

320, sample for a minimum of 1 

hour. 

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

(PM).

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

run. 

OR OR 

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

run. 

OR OR 

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

run. 

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

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

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

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

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

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

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

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

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

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

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

For ASTM D6348–03 2 or Method 

320, sample for a minimum of 1 

hour. 

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

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

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

1Gross 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 (or, in the case of IGCC EGUs, some other 

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

5 Duct burners on natural gas; gross electric output. 

■ 20. Revise Table 4 to Subpart UUUUU 

of Part 63 to read as follows: 


tkelley on DSK3SPTVN1PROD with RULES
Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 24091 

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

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

If you demonstrate compliance 

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

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

total non-mercury HAP metals (total HAP metals, for liquid oil-fired units), or individual non-mercury HAP 

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

2. PM CPMS for a new EGU .......... Maintain the 30-boiler operating day rolling average PM CPMS output determined in accordance with the 

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

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

■ 21. Revise footnote 4 of Table 5 to 

Subpart UUUUU of Part 63 to read as 

follows: 

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

*******

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: 

■ 22. Revise Table 6 to Subpart UUUUU 

of Part 63 to read as follows: 

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

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

If you have an applicable 

emission limit for . . . 

And you choose to establish 

PM CPMS operating limits, you 

must . . . 

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

procedures . . . 

1. Filterable 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. 


tkelley on DSK3SPTVN1PROD with RULES
24092 Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 

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

[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 . . . 

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 performance 

test. 

3. Determine the PM CPMS 

operating limit in accordance with the requirements 

of § 63.10023(b)(2) from 

data obtained during the 

performance test demonstrating compliance with 

the filterable PM or HAP 

metals emissions limitations. 

■ 23. Revise Table 7 to Subpart UUUUU 

of Part 63 to read as follows: 

TABLE 7 TO SUBPART UUUUU OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE

[As stated in § 63.10021, you must show continuous compliance with the emission limitations for affected sources according to the following] 

If you use one of the following to 

meet applicable emissions limits, 

operating limits, or work practice 

standards . . . 

You demonstrate continuous compliance by . . . 

1. CEMS to measure filterable PM, 

SO2, HCl, HF, or Hg emissions, 

or using a sorbent trap monitoring system to measure Hg.

Calculating the 30- (or 90-) boiler operating day rolling arithmetic average emissions rate in units of the applicable emissions standard basis at the end of each boiler operating day using all of the quality assured 

hourly average CEMS or sorbent trap data for the previous 30- (or 90-) boiler operating days, excluding 

data recorded during periods of startup or shutdown. 

2. PM CPMS to measure compliance with a parametric operating 

limit.

Calculating the 30- (or 90-) boiler operating day rolling arithmetic average of all of the quality assured 

hourly average PM CPMS output data (e.g., milliamps, PM concentration, raw data signal) collected for 

all operating hours for the previous 30- (or 90-) boiler operating days, excluding data recorded during 

periods of startup or shutdown. 

3. Site-specific monitoring using 

CMS for liquid oil-fired EGUs for 

HCl and HF emission limit monitoring.

If applicable, by conducting the monitoring in accordance with an approved site-specific monitoring plan. 

4. Quarterly performance testing for 

coal-fired, solid oil derived fired, 

or liquid oil-fired EGUs to measure compliance with one or more 

non-PM (or its alternative emission limits) applicable emissions 

limit in Table 1 or 2, or PM (or its 

alternative emission limits) applicable emissions limit in Table 2.

Calculating the results of the testing in units of the applicable emissions standard. 

5. Conducting periodic performance 

tune-ups of your EGU(s).

Conducting periodic performance tune-ups of your EGU(s), as specified in § 63.10021(e). 

6. Work practice standards for coalfired, liquid oil-fired, or solid oilderived fuel-fired EGUs during 

startup.

Operating in accordance with Table 3. 

7. Work practice standards for coalfired, liquid oil-fired, or solid oilderived fuel-fired EGUs during 

shutdown.

Operating in accordance with Table 3. 

■ 24. Revise Table 9 to Subpart UUUUU 

of Part 63 to read as follows: 


tkelley on DSK3SPTVN1PROD with RULES
Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 24093 

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

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

Citation Subject Applies to subpart UUUUU 

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

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

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

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

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

§ 63.6(a), (b)(1)–(b)(5), (b)(7), (c), 

(f)(2)–(3), (g), (h)(2)–(h)(9), (i), (j).

Compliance with Standards and 

Maintenance Requirements.

Yes. 

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

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

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

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

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

§ 63.7(a), (b), (c), (d), (e)(2)–(e)(9), 

(f), (g), and (h).

Performance Testing Requirements.Yes. 

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

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

63.8(c)(1)(i) ...................................... General duty to minimize emissions and CMS operation.No. See § 63.10000(b) for general duty requirement. 

§ 63.8(c)(1)(iii) ................................. Requirement to develop SSM Plan 

for CMS.

No. 

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

plans are not required. 

§ 63.9 ............................................... Notification requirements ............... Yes, except for the 60-day notification prior to conducting a performance test in § 63.9(d); instead use a 30-day notification period per 

§ 63.10030(d). 

§ 63.10(a), (b)(1), (c), (d)(1)–(2), 

(e), and (f).

Recordkeeping and Reporting Requirements.Yes, except for the requirements to submit written reports under 

§ 63.10(e)(3)(v). 

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

duration of startups and shutdowns.

No. 

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

and (2) actions taken during malfunction. 

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

§ 63.10(b)(2)(iv) ............................... Actions taken to minimize emissions during SSM.No. 

§ 63.10(b)(2)(v) ................................ Actions taken to minimize emissions during SSM.No. 

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

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

§ 63.10(b)(3),and (d)(3)–(5) ............. ........................................................ No. 

§ 63.10(c)(7) .................................... Additional recordkeeping requirements for CMS—identifying 

exceedances and excess emissions.

Yes. 

§ 63.10(c)(8) .................................... Additional recordkeeping requirements for CMS—identifying 

exceedances and excess emissions.

Yes. 

§ 63.10(c)(10) .................................. Recording nature and cause of 

malfunctions.

No. See 63.10032(g) and (h) for malfunctions recordkeeping requirements. 

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

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

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

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

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

§ 63.13–63.16 .................................. Addresses, Incorporation by Reference, Availability of Information, Performance Track Provisions.Yes. 

§ 63.1(a)(5), (a)(7)–(a)(9), (b)(2), 

(c)(3)–(4), (d), 63.6(b)(6), (c)(3), 

(c)(4), (d), (e)(2), (e)(3)(ii), (h)(3), 

(h)(5)(iv), 63.8(a)(3), 63.9(b)(3), 

(h)(4), 63.10(c)(2)–(4), (c)(9).

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


tkelley on DSK3SPTVN1PROD with RULES
24094 Federal Register / Vol. 78, No. 79 / Wednesday, April 24, 2013 / Rules and Regulations 

■ 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 

also 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. 2013–07859 Filed 4–23–13; 8:45 am] 

BILLING CODE 6560–50–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 180 

[EPA–HQ–OPP–2012–0282; FRL–9384–2] 

Azoxystrobin; Pesticide Tolerances 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: This regulation establishes 

tolerances for residues of azoxystrobin 

in or on multiple commodities 

discussed later in this document. 

Syngenta Crop Protection, LLC 

requested these tolerances under the 

Federal Food, Drug, and Cosmetic Act 

(FFDCA). 

DATES: This regulation is effective April 

24, 2013. Objections and requests for 

hearings must be received on or before 

June 24, 2013, and must be filed in 

accordance with the instructions 

provided in 40 CFR part 178 (see also 

Unit I.C. of the SUPPLEMENTARY

INFORMATION). 

ADDRESSES: The docket for these 

actions, identified by docket 

identification (ID) number EPA–HQ– 

OPP–2012–0282, is available at http:// 

www.regulations.gov or at the Office of 

Pesticide Programs Regulatory Public 

Docket (OPP Docket) in the 

Environmental Protection Agency 

Docket Center (EPA/DC), EPA West 

Bldg., Rm. 3334, 1301 Constitution Ave. 

NW., Washington, DC 20460–0001. 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 OPP 

Docket is (703) 305–5805. Please review 

the visitor instructions and additional 

information about the docket available 

at http://www.epa.gov/dockets. 

FOR FURTHER INFORMATION CONTACT: Erin 

Malone, Registration Division (7505P), 

Office of Pesticide Programs, 

Environmental Protection Agency, 1200 

Pennsylvania Ave. NW., Washington, 

DC 20460–0001; telephone number: 

(703) 347–0253; email address: 

Malone.Erin@epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. General Information 

A. Does this action apply to me? 

You may be potentially affected by 

this action if you are an agricultural 

producer, food manufacturer, or 

pesticide manufacturer. The following 

list of North American Industrial 

Classification System (NAICS) codes is 

not intended to be exhaustive, but rather 

provides a guide to help readers 

determine whether this document 

applies to them. Potentially affected 

entities may include: 

• Crop production (NAICS code 111). 

• Animal production (NAICS code 

112). 

• Food manufacturing (NAICS code 

311). 

• Pesticide manufacturing (NAICS 

code 32532). 

B. How can I get electronic access to 

other related information? 

You may access a frequently updated 

electronic version of EPA’s tolerance 

regulations at 40 CFR part 180 through 

the Government Printing Office’s eCFR 

site at http://www.ecfr.gov/cgi-bin/textidx?&c=ecfr&tpl=/ecfrbrowse/Title40/ 

40tab_02.tpl. 

C. How can I file an objection or hearing 

request? 

Under FFDCA section 408(g), 21 

U.S.C. 346a, any person may file an 

objection to any aspect of this regulation 

and may also request a hearing on those 

objections. You must file your objection 

or request a hearing on this regulation 

in accordance with the instructions 

provided in 40 CFR part 178. To ensure 

proper receipt by EPA, you must 

identify docket ID number EPA–HQ– 

OPP–2012–0282 in the subject line on 

the first page of your submission. All 

objections and requests for a hearing 

must be in writing, and must be 

received by the Hearing Clerk on or 

before June 24, 2013. Addresses for mail 

and hand delivery of objections and 

hearing requests are provided in 40 CFR 

178.25(b). 

In addition to filing an objection or 

hearing request with the Hearing Clerk 

as described in 40 CFR part 178, please 

submit a copy of the filing (excluding 

any Confidential Business Information 

(CBI)) for inclusion in the public docket. 

Information not marked confidential 

pursuant to 40 CFR part 2 may be 

disclosed publicly by EPA without prior 

notice. Submit the non-CBI copy of your 

objection or hearing request, identified 

by docket ID number EPA–HQ–OPP– 

2012–0282, by one of the following 

methods: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the online 

instructions for submitting comments. 

Do not submit electronically any 

information you consider to be CBI or 

other information whose disclosure is 

restricted by statute. 

• Mail: OPP Docket, Environmental 

Protection Agency Docket Center (EPA/ 

DC), (28221T), 1200 Pennsylvania Ave. 

NW., Washington, DC 20460–0001. 

• Hand Delivery: To make special 

arrangements for hand delivery or 

delivery of boxed information, please 

follow the instructions at http:// 

www.epa.gov/dockets/contacts.htm. 

Additional instructions on 

commenting or visiting the docket, 

along with more information about 

dockets generally, is available at 

http://www.epa.gov/dockets. 

II. Summary of Petitioned-For 

Tolerance 

In the Federal Register of April 4, 

2012 (77 FR 20336) (FRL–9340–4), EPA 

issued a document pursuant to FFDCA 

section 408(d)(3), 21 U.S.C. 346a(d)(3), 

announcing the filing of a pesticide 

petition (PP 1E7945) by Syngenta Crop 

Protection, LLC, P.O. Box 18300, 

Greensboro, NC 27419–8300. The 

petition requested that 40 CFR 180.507 

be amended by establishing an import 

tolerance for residues of the fungicide 

azoxystrobin, [methyl(E)-2-(2-(6-(2- 

cyanophenoxy) pyrimidin-4- 

yloxy)phenyl)-3-methoxyacrylate], and 

the Z-isomer of azoxystrobin, 

[methyl(Z)-2-(2-(6-(2- 


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