32710 Federal Register / Vol. 72, No. 113 / Wednesday, June 13, 2007 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[EPA–HQ–OAR–2005–0031; FRL–8302–3] 

RIN 2060–AN97 

Standards of Performance for FossilFuel-Fired Steam Generators for Which 

Construction Is Commenced After 

August 17, 1971; Standards of 

Performance for Electric Utility Steam 

Generating Units for Which 

Construction Is Commenced After 

September 18, 1978; Standards of 

Performance for IndustrialCommercial-Institutional Steam 

Generating Units; and Standards of 

Performance for Small IndustrialCommercial-Institutional Steam 

Generating Units 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final reconsideration. 

SUMMARY: EPA is amending the new 

source performance standards (NSPS) 

for electric utility steam generating units 

and industrial-commercial-institutional 

steam generating units. These 

amendments to the regulations are to 

add compliance alternatives for owners 

and operators of certain affected 

sources, revise certain recordkeeping 

and reporting requirements, correct 

technical and editorial errors, and 

update the grammatical style of the four 

subparts to be more consistent across all 

of the subparts. 

DATES: This rule is effective on June 13, 

2007. The incorporation by reference of 

certain publications listed in these rules 

is approved by the Director of the 

Federal Register as of June 13, 2007. 

ADDRESSES: EPA has established a 

docket for this action under Docket ID 

No. EPA–HQ–OAR–2005–0031. All 

documents in the docket are listed in 

the Federal Docket Management System 

index at http://www.regulations.gov. 

Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

or other information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

is not placed on the Internet and will be 

publicly available only in hard copy 

form. Publicly available docket 

materials are available either 

electronically through 

www.regulations.gov or in hard copy at 

the EPA Docket Center, Public Reading 

Room, EPA West, Room 3334, 1301 

Constitution Ave., 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: Mr. 

Christian Fellner, Energy Strategies 

Group, Sector Policies and Programs 

Division (D243–01), U.S. EPA, Research 

Triangle Park, NC 27711, telephone 

number (919) 541–4003, facsimile 

number (919) 541–5450, electronic mail 

(e-mail) 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. Where can I get a copy of this 

document? 

C. Judicial Review 

II. Background Information 

III. Final Amendments and Changes Since 

Proposal 

IV. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer 

Advancement Act 

J. Congressional Review Act 

I. General Information 

A. Does this action apply to me? 

The regulated categories and entities 

potentially affected by this final action 

include, but are not limited to, the 

following: 

Category NAICS code 1 Examples of potentially regulated entities 

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

Federal Government ................................................................. 22112 Fossil fuel-fired electric utility steam generating units owned 

by the Federal Government. 

State/local/tribal government .................................................... 22112 Fossil fuel-fired electric utility steam generating units owned 

by municipalities. 

921150 Fossil fuel-fired electric steam generating units in Indian 

Country. 

Any industrial, commercial, or institutional facility using a 

steam generating unit as defined in 60.40b or 60.40c.

211 Extractors of crude petroleum and natural gas. 

321 Manufacturers of lumber and wood products. 

322 Pulp and paper mills. 

325 Chemical manufacturers. 

324 Petroleum refiners and manufacturers of coal products. 

316, 326, 339 Manufacturers of rubber and miscellaneous plastic products. 

331 Steel works, blast furnaces. 

332 Electroplating, plating, polishing, anodizing, and coloring. 

336 Manufacturers of motor vehicle parts and accessories. 

221 Electric, gas, and sanitary services. 

622 Health services. 

611 Educational Services. 

1 North American Industry Classification System (NAICS) code. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by this action. To determine 

whether your facility is regulated by this 

action, you should examine the 

applicability criteria in § 60.40a, 60.40b, 

or 60.40c of 40 CFR part 60. If you have 

any questions regarding the 

applicability of this action to a 

particular entity, consult either the air 

permit authority for the entity or your 


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EPA regional representative as listed in 

40 CFR 63.13 of subpart A (General 

Provisions). 

B. Where can I get a copy of this 

document? 

In addition to being available in the 

docket, an electronic copy of this final 

action will also be available on the 

Worldwide Web (WWW) through the 

Technology Transfer Network (TTN). 

Following signature, a copy of this final 

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 section 307(b)(1) of the Clean 

Air Act (CAA), judicial review of these 

final rules is available only by filing a 

petition for review in the U.S. Court of 

Appeals for the District of Columbia 

Circuit by August 13, 2007. Under 

section 307(d)(7)(B) of the CAA, only an 

objection to these final rules that was 

raised with reasonable specificity 

during the period for public comment 

can be raised during judicial review. 

Moreover, under section 307(b)(2) of the 

CAA, the requirements established by 

these final rules may not be challenged 

separately in any civil or criminal 

proceedings brought by EPA to enforce 

these requirements. 

II. Background Information 

In response to petitions for 

reconsideration filed by the Utility Air 

Regulatory Group and the Council of 

Industrial Boiler Owners of the 

amendments to the new source 

performance standards for steam 

generating units that EPA promulgated 

on February 27, 2006 (71 FR 9866), EPA 

proposed revised amendments to 

address issues for which the petitioners 

requested reconsideration (see docket 

entries EPA–HQ–OAR–2005–0031–0224 

and EPA–HQ–OAR–2005–0031–0225). 

EPA proposed on February 9, 2007, (72 

FR 6320) to amend 40 CFR part 60, 

subparts D, Da, Db, and Dc to clarify the 

intent for applying and implementing 

specific rule requirements, provide 

additional compliance alternatives, and 

to correct unintentional technical 

omissions and editorial errors. In 

addition, EPA proposed to republish 40 

CFR 60.17 (Incorporations by reference) 

and subparts D, Da, Db, and Dc in their 

entirety for the purpose of revising the 

wording and writing style to be more 

consistent across all the NSPS subparts 

applicable to steam generating units. 

A 30-day comment period (February 

9, 2007 to March 12, 2007) was 

provided to accept comments on the 

proposed rule. An opportunity for a 

public hearing was provided to allow 

any interested persons to present oral 

comments on the proposed rule. 

However, EPA did not receive a request 

for a formal public hearing, so a public 

hearing was not held. EPA did receive 

a request for a 15-day extension to the 

comment period. EPA granted an 

extension of the public comment period 

to March 26, 2007 (72 FR 9903, March 

6, 2007). We received comments on the 

proposed amendments from 20 

commenters during the comment 

period. 

III. Final Amendments and Changes 

Since Proposal 

We are amending 40 CFR part 60, 

subparts D, Da, Db, and Dc to add 

compliance alternatives for owners and 

operators of certain affected sources, 

revise certain recordkeeping and 

reporting requirements, correct 

technical and editorial errors, and 

update the grammatical style of the four 

subparts to be more consistent across all 

of the subparts. This action promulgates 

the proposed regulatory language for the 

amendments except for those significant 

provisions, as noted below, for which 

modifications were made to the 

regulatory language for the final 

amendments in response to specific 

public comments. EPA did not receive 

negative comments on the conforming 

changes to the regulatory text and is, 

therefore, finalizing all those changes. 

The final amendments promulgated 

by this action reflect EPA’s 

consideration of the comments received 

on the proposal. EPA’s responses to the 

substantive public comments on the 

proposal are presented in a comment 

summary and response document 

available in Docket ID No. EPA–HQ–

OAR–2005–0031. 

The requirements in subpart Da for 

demonstrating continuous compliance 

with the particulate matter (PM) 

emission limits for affected electric 

utility steam generating units that 

commence construction, reconstruction, 

or modification after February 28, 2005, 

have been revised since proposal in 

response to comments. EPA is retaining 

the provision, established in the 

February 27, 2006 final rule, allowing 

the optional use of PM continuous 

emission monitoring systems (CEMS) to 

steam generating units for 

demonstration of compliance with rule 

requirements related to controlling PM 

emissions. Owners and operators 

choosing to install and properly operate 

PM CEMS must demonstrate 

compliance with the applicable PM 

emission limit on a daily basis and are 

not required to install a continuous 

opacity monitoring system (COMS) or to 

monitor PM control device performance. 

We recognize that experience using 

PM CEMS at electric utility power 

plants in the United States is limited, 

and not all affected owners and 

operators will choose to use PM CEMS. 

Therefore, the final amendments allow 

owners and operators of affected electric 

utility steam generating units 

constructed, reconstructed, or modified 

after February 28, 2005, to demonstrate 

compliance with the PM emissions limit 

using periodic PM emissions 

performance testing and continuous 

monitoring of the PM control device 

performance using one of two 

alternatives. The first monitoring 

alternative is for an owner or operator 

of an affected source to monitor PM 

control device performance based on the 

opacity level measured during the stack 

performance test conducted to 

demonstrate compliance with the 

applicable PM emissions limit. The 

second alternative available to owners 

and operators depends on the type of 

PM control device used for the electric 

utility steam generating unit. The owner 

or operator of an affected source that 

uses an electrostatic precipitator (ESP) 

can elect to monitor performance of the 

control device using an ESP predictive 

emissions model. An owner or operator 

of an affected source that uses a fabric 

filter can elect to monitor control device 

performance using a bag leak detection 

system. One significant change from the 

proposal is that owners or operators of 

affected source that use parametric 

monitoring of PM emissions will have a 

grace period to bring the monitoring 

parameters back into the range 

established during the most recent PM 

emissions performance test prior to the 

requirement to conduct a new PM 

emissions performance test. The grace 

period does not apply to the 6-minute 

opacity standard and owners and 

operators of affected sources must 

continue to report excess 6-minute 

opacity measurements. 

EPA has finalized several other 

alternatives to provide owners and 

operators of affected electric utility 

steam generating units additional 

flexibility in complying with the NSPS. 

EPA has finalized the optional use of 

Part 75 NOX and SO2 CEMS calibration 

procedures to satisfy Part 60 

requirements as proposed, the 

amendments to § 60.13 providing a 

standard methodology for validating 

partial operating hours, and the 

amendments to Appendix B of Part 60 

allowing the calibration drift test be 


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conducted over 7 consecutive operating 

days instead of 7 consecutive calendar 

days and the relative accuracy test audit 

flexibility (as described in docket entry 

EPA–HQ–OAR–2005–0031–0234). In 

addition, EPA has finalized the option 

for steam generating units subject to 

subpart D allowing affected owners and 

operators to choose as an alternative to 

complying with the applicable NOX and 

SO2 emission limits in the rule to 

comply with the 30-day average NOX

and SO2 standards for modified sources 

in subparts Da and Db, as applicable to 

the affected source. 

For industrial/commercial/ 

institutional steam generating units 

subject to subpart Db and burning coke 

oven gas (COG), we have expanded the 

applicability of the 30-day annual 

exemption from the SO2 emissions limit 

to all units subject to subpart Db that 

burn COG. The amendments to subpart 

Db promulgated in February 27, 2006, 

added this flexibility for those steam 

generating units constructed, 

reconstructed, or modified after 

February 28, 2005, to account for 

byproduct plant maintenance. Based on 

comments we received, the amendments 

promulgated by this action provide the 

same compliance flexibility to the 

owner or operator of any COG-fired 

steam generating unit subject to subpart 

Db. 

The final amendments add to subparts 

D, Da, Db, and Dc monitoring 

alternatives to existing requirements to 

use COMS for owners and operators of 

steam generating units burning gaseous 

fuels or low sulfur fuel oils. Owners and 

operators of electric utility steam 

generating units subject to subpart D or 

Da may elect to use a carbon monoxide 

(CO) CEMS in place of the COMS. 

Owners and operators of industrial/ 

commercial/institutional steam 

generating units subject to subpart Db or 

Dc may elect to either use a CO CEMS 

or to operate according to a site-specific 

monitoring plan in place of using a 

COMS. 

Finally, minor revisions to the 

proposed regulatory language were 

made to clarify specific provisions or to 

correct unintentional technical 

omissions and terminology, 

typographical, printing, and 

grammatical errors that were identified 

in the proposed rule. These changes 

include revising appropriate definitions 

and requirements in subpart Da to 

clarify the applicability and 

implementation of the subpart Da 

provisions to integrated coal gasification 

combined cycle electric utility power 

plants. 

IV. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is, therefore, not 

subject to review under the Executive 

Order. EPA has concluded that the 

amendments EPA is promulgating will 

not change the costs or benefits of the 

rule. 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden under the 

provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. The final 

amendments result in no changes to the 

information collection requirements of 

the existing standards of performance 

and would have no impact on the 

information collection estimate of 

projected cost and hour burden made 

and approved by the Office of 

Management and Budget (OMB) during 

the development of the existing 

standards of performance. Therefore, the 

information collection requests have not 

been amended. OMB has previously 

approved the information collection 

requirements contained in the existing 

standards of performance (40 CFR part 

60, subparts D, Da, Db, and Dc) under 

the provisions of the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq., 

at the time the standards were 

promulgated on June 11, 1979 (40 CFR 

part 60, subpart Da, 44 FR 33580), 

November 25, 1986 (40 CFR part 60, 

subpart Db, 51 FR 42768), and 

September 12, 1990 (40 CFR part 60, 

subpart Dc, 55 FR 37674). OMB 

assigned OMB control numbers 2060–

0023 (ICR 1053.08) for 40 CFR part 60, 

subpart Da; 2060–0072 (ICR 1088.11) for 

40 CFR part 60, subpart Db; 2060–0202 

(ICR 1564.06) for 40 CFR part 60, 

subpart Dc. Copies of the information 

collection request document(s) may be 

obtained from Susan Auby, Collection 

Strategies Division, U.S. EPA (2822T), 

1200 Pennsylvania Ave., NW., 

Washington, DC 20460, by e-mail at 

auby.susan@epa.gov, or by calling (202) 

566–1672. 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a 

Federal agency. This includes the time 

needed to review instructions; develop, 

acquire, install, and utilize technology 

and systems for the purposes of 

collecting, validating, and verifying 

information, processing and 

maintaining information, and disclosing 

and providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to a collection of information 

unless it displays a currently valid OMB 

control number. OMB control numbers 

for EPA’s regulations in 40 CFR are 

listed in 40 CFR part 9. 

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 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of the final amendments on small 

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

small business as defined by the Small 

Business Administration’s 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 than 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. 

After considering the economic 

impacts of this final rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

Although this action will not have a 

significant economic impact on a 

substantial number of small entities, 

EPA nonetheless has tried to reduce the 

impact of this rule on small entities. 

EPA is reducing the fuel usage 

recordkeeping requirement for subpart 

Dc facilities. In addition, EPA is 

minimizing the continuous opacity 

monitoring requirements for certain oilfired facilities. EPA has, therefore, 

concluded that this action will relieve 

regulatory burden for the majority of 

affected small entities. EPA continues to 

be interested in the potential impacts of 

the rule on small entities and welcomes 

comments on issues related to such 

impacts. 


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D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and tribal governments and the private 

sector. Under section 202 of the UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to State, local, 

and tribal governments, in the aggregate, 

or to the private sector, of $100 million 

or more in any one year. Before 

promulgating an EPA rule for which a 

written statement is needed, section 205 

of the UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most costeffective or least burdensome alternative 

that achieves the objectives of the rule. 

The provisions of section 205 do not 

apply when they are inconsistent with 

applicable law. Moreover, section 205 

allows EPA to adopt an alternative other 

than the least costly, most cost-effective 

or least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including tribal 

governments, it must have developed 

under section 203 of the UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

EPA has determined that the final 

amendments will contain no Federal 

mandates that may result in 

expenditures of $100 million or more 

for State, local, and tribal governments, 

in the aggregate, or the private sector in 

any 1 year. Thus, the final amendments 

are not subject to the requirements of 

section 202 and 205 of the UMRA. In 

addition, EPA has determined that the 

final amendments contain no regulatory 

requirements that might significantly or 

uniquely affect small governments 

because the burden is small and the 

regulation does not unfairly apply to 

small governments. Therefore, the final 

amendments are not subject to the 

requirements of section 203 of the 

UMRA. 

E. Executive Order 13132: Federalism 

Executive Order 13132, entitled 

‘‘Federalism’’ (64 FR 43255, August 10, 

1999), requires EPA to develop an 

accountable process to ensure 

‘‘meaningful and timely input by State 

and local officials in the development of 

regulatory policies that have federalism 

implications.’’ ‘‘Policies that have 

federalism implications’’ is defined in 

the Executive Order to include 

regulations that 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.’’

The final amendments do not have 

federalism implications. They 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 

Executive Order 13132. The final 

amendments will not impose substantial 

direct compliance costs on State or local 

governments; it will not preempt State 

law. Thus, Executive Order 13132 does 

not apply to the final amendments. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

‘‘Consultation and Coordination with 

Indian Tribal Governments’’ (65 FR 

67249, November 9, 2000), requires EPA 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ The final amendments do 

not have tribal implications, as specified 

in Executive Order 13175. While utility 

steam generating units are located on 

tribal lands EPA is not aware of any that 

are tribally owned. To the extend that 

institutional steam generating units are 

tribally owned the final amendments 

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. Thus, 

Executive Order 13175 does not apply 

to the final amendments. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

Executive Order 13045 (62 FR 19885, 

April 23, 1997) applies to any rule that: 

(1) Is determined to be ‘‘economically 

significant’’ as defined under Executive 

Order 12866, and (2) concerns an 

environmental health or safety risk that 

EPA has reason to believe may have a 

disproportionate effect on children. If 

the regulatory action meets both criteria, 

the Agency must evaluate the 

environmental health or safety effects of 

the planned rule on children, and 

explain why the planned regulation is 

preferable to other potentially effective 

and reasonably feasible alternatives 

considered by the Agency. 

This action is not subject to the 

Executive Order because it is not 

economically significant as defined 

under Executive Order 12866, and 

because EPA interprets Executive Order 

13045 as applying only to those 

regulatory actions that are based on 

health or safety risks, such that the 

analysis required under section 5–501 of 

the Order has the potential to influence 

the regulation. The final amendments 

are based on technology performance 

and not on health or safety risks and, 

therefore, are not subject to Executive 

Order 13045. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

The final amendments are not a 

‘‘significant energy action’’: As defined 

in Executive Order 13211, ‘‘Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use’’ (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 

because it only clarifies our intent and 

corrects errors in the existing rule. 

Further, we have concluded that the 

final amendments are not likely to have 

any adverse energy effects. 

I. National Technology Transfer 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law 104–

113, Section 12(d)(15 U.S.C. 272 note) 

directs us to use voluntary consensus 

standards in our regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. 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 directs us to provide 

Congress, through OMB, explanations 

when we decide not use available and 

applicable voluntary consensus 

standards. 


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This action does not involve any new 

technical standards or the incorporation 

by reference of existing technical 

standards. Therefore, the consideration 

of voluntary consensus standards is not 

relevant to this action. 

J. 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 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing these final 

amendments 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 final 

rules 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). 

These final amendments will be 

effective on June 13, 2007. 

List of Subjects in 40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Incorporation by 

reference, Intergovernmental relations, 

Reporting and recordkeeping 

requirements. 

Dated: April 13, 2007. 

Stephen L. Johnson, 

Administrator. 

■ For the reasons stated in the preamble, 

title 40, chapter I, part 60, of the Code 

of the Federal Regulations is amended 

as follows: 

PART 60—[AMENDED] 

■ 1. The authority citation for part 60 

continues to read as follows: 

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

Subpart A—[Amended] 

■ 2. Section 60.13 is amended by 

revising paragraph (h) to read as 

follows: 

§ 60.13 Monitoring requirements. 

* * * * * 

(h)(1) Owners or operators of all 

continuous monitoring systems for 

measurement of opacity shall reduce all 

data to 6-minute averages and for 

continuous monitoring systems other 

than opacity to 1-hour averages for time 

periods as defined in § 60.2. Six-minute 

opacity averages shall be calculated 

from 36 or more data points equally 

spaced over each 6-minute period. 

(2) For continuous monitoring 

systems other than opacity, 1-hour 

averages shall be computed as follows, 

except that the provisions pertaining to 

the validation of partial operating hours 

are only applicable for affected facilities 

that are required by the applicable 

subpart to include partial hours in the 

emission calculations: 

(i) Except as provided under 

paragraph (h)(2)(iii) of this section, for 

a full operating hour (any clock hour 

with 60 minutes of unit operation), at 

least four valid data points are required 

to calculate the hourly average, i.e., one 

data point in each of the 15-minute 

quadrants of the hour. 

(ii) Except as provided under 

paragraph (h)(2)(iii) of this section, for 

a partial operating hour (any clock hour 

with less than 60 minutes of unit 

operation), at least one valid data point 

in each 15-minute quadrant of the hour 

in which the unit operates is required to 

calculate the hourly average. 

(iii) For any operating hour in which 

required maintenance or qualityassurance activities are performed: 

(A) If the unit operates in two or more 

quadrants of the hour, a minimum of 

two valid data points, separated by at 

least 15 minutes, is required to calculate 

the hourly average; or 

(B) If the unit operates in only one 

quadrant of the hour, at least one valid 

data point is required to calculate the 

hourly average. 

(iv) If a daily calibration error check 

is failed during any operating hour, all 

data for that hour shall be invalidated, 

unless a subsequent calibration error 

test is passed in the same hour and the 

requirements of paragraph (h)(2)(iii) of 

this section are met, based solely on 

valid data recorded after the successful 

calibration. 

(v) For each full or partial operating 

hour, all valid data points shall be used 

to calculate the hourly average. 

(vi) Except as provided under 

paragraph (h)(2)(vii) of this section, data 

recorded during periods of continuous 

monitoring system breakdown, repair, 

calibration checks, and zero and span 

adjustments shall not be included in the 

data averages computed under this 

paragraph. 

(vii) Owners and operators complying 

with the requirements of § 60.7(f)(1) or 

(2) must include any data recorded 

during periods of monitor breakdown or 

malfunction in the data averages. 

(viii) When specified in an applicable 

subpart, hourly averages for certain 

partial operating hours shall not be 

computed or included in the emission 

averages (e.g. hours with < 30 minutes 

of unit operation under § 60.47b(d)). 

(ix) Either arithmetic or integrated 

averaging of all data may be used to 

calculate the hourly averages. The data 

may be recorded in reduced or 

nonreduced form (e.g., ppm pollutant 

and percent O2 or ng/J of pollutant). 

(3) All excess emissions shall be 

converted into units of the standard 

using the applicable conversion 

procedures specified in the applicable 

subpart. After conversion into units of 

the standard, the data may be rounded 

to the same number of significant digits 

used in the applicable subpart to specify 

the emission limit. 

* * * * * 

§ 60.17 [Amended] 

■ 3. Section 60.17 is amended by 

revising paragraphs (a) and (h)(2) to read 

as follows: 

* * * * * 

(a) The following materials are 

available for purchase from at least one 

of the following addresses: American 

Society for Testing and Materials 

(ASTM), 100 Barr Harbor Drive, Post 

Office Box C700, West Conshohocken, 

PA 19428–2959; or ProQuest, 300 North 

Zeeb Road, Ann Arbor, MI 48106. 

(1) ASTM A99–76, 82 (Reapproved 

1987), Standard Specification for 

Ferromanganese, incorporation by 

reference (IBR) approved for § 60.261. 

(2) ASTM A100–69, 74, 93, Standard 

Specification for Ferrosilicon, IBR 

approved for § 60.261. 

(3) ASTM A101–73, 93, Standard 

Specification for Ferrochromium, IBR 

approved for § 60.261. 

(4) ASTM A482–76, 93, Standard 

Specification for Ferrochromesilicon, 

IBR approved for § 60.261. 

(5) ASTM A483–64, 74 (Reapproved 

1988), Standard Specification for 

Silicomanganese, IBR approved for 

§ 60.261. 

(6) ASTM A495–76, 94, Standard 

Specification for Calcium-Silicon and 

Calcium Manganese-Silicon, IBR 

approved for § 60.261. 

(7) ASTM D86–78, 82, 90, 93, 95, 96, 

Distillation of Petroleum Products, IBR 

approved for §§ 60.562–2(d), 60.593(d), 

and 60.633(h). 

(8) ASTM D129–64, 78, 95, 00, 

Standard Test Method for Sulfur in 

Petroleum Products (General Bomb 

Method), IBR approved for 

§§ 60.106(j)(2), 60.335(b)(10)(i), and 

Appendix A: Method 19, 12.5.2.2.3. 

(9) ASTM D129–00 (Reapproved 

2005), Standard Test Method for Sulfur 

in Petroleum Products (General Bomb 

Method), IBR approved for 

§ 60.4415(a)(1)(i). 


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(10) ASTM D240–76, 92, Standard 

Test Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter, IBR approved for 

§§ 60.46(c), 60.296(b), and Appendix A: 

Method 19, Section 12.5.2.2.3. 

(11) ASTM D270–65, 75, Standard 

Method of Sampling Petroleum and 

Petroleum Products, IBR approved for 

Appendix A: Method 19, Section 

12.5.2.2.1. 

(12) ASTM D323–82, 94, Test Method 

for Vapor Pressure of Petroleum 

Products (Reid Method), IBR approved 

for §§ 60.111(l), 60.111a(g), 60.111b(g), 

and 60.116b(f)(2)(ii). 

(13) ASTM D388–77, 90, 91, 95, 98a, 

99 (Reapproved 2004) ε1, Standard 

Specification for Classification of Coals 

by Rank, IBR approved for 

§§ 60.24(h)(8), 60.41 of subpart D of this 

part, 60.45(f)(4)(i), 60.45(f)(4)(ii), 

60.45(f)(4)(vi), 60.41Da of subpart Da of 

this part, 60.41b of subpart Db of this 

part, 60.41c of subpart Dc of this part, 

and 60.4102. 

(14) ASTM D388–77, 90, 91, 95, 98a, 

Standard Specification for Classification 

of Coals by Rank, IBR approved for 

§§ 60.251(b) and (c) of subpart Y of this 

part. 

(15) ASTM D396–78, 89, 90, 92, 96, 

98, Standard Specification for Fuel Oils, 

IBR approved for §§ 60.41b of subpart 

Db of this part, 60.41c of subpart Dc of 

this part, 60.111(b) of subpart K of this 

part, and 60.111a(b) of subpart Ka of 

this part. 

(16) ASTM D975–78, 96, 98a, 

Standard Specification for Diesel Fuel 

Oils, IBR approved for §§ 60.111(b) of 

subpart K of this part and 60.111a(b) of 

subpart Ka of this part. 

(17) ASTM D1072–80, 90 

(Reapproved 1994), Standard Test 

Method for Total Sulfur in Fuel Gases, 

IBR approved for § 60.335(b)(10)(ii). 

(18) ASTM D1072–90 (Reapproved 

1999), Standard Test Method for Total 

Sulfur in Fuel Gases, IBR approved for 

§ 60.4415(a)(1)(ii). 

(19) ASTM D1137–53, 75, Standard 

Method for Analysis of Natural Gases 

and Related Types of Gaseous Mixtures 

by the Mass Spectrometer, IBR approved 

for § 60.45(f)(5)(i). 

(20) ASTM D1193–77, 91, Standard 

Specification for Reagent Water, IBR 

approved for Appendix A: Method 5, 

Section 7.1.3; Method 5E, Section 7.2.1; 

Method 5F, Section 7.2.1; Method 6, 

Section 7.1.1; Method 7, Section 7.1.1; 

Method 7C, Section 7.1.1; Method 7D, 

Section 7.1.1; Method 10A, Section 

7.1.1; Method 11, Section 7.1.3; Method 

12, Section 7.1.3; Method 13A, Section 

7.1.2; Method 26, Section 7.1.2; Method 

26A, Section 7.1.2; and Method 29, 

Section 7.2.2. 

(21) ASTM D1266–87, 91, 98, 

Standard Test Method for Sulfur in 

Petroleum Products (Lamp Method), IBR 

approved for §§ 60.106(j)(2) and 

60.335(b)(10)(i). 

(22) ASTM D1266–98 (Reapproved 

2003)e1, Standard Test Method for 

Sulfur in Petroleum Products (Lamp 

Method), IBR approved for 

§ 60.4415(a)(1)(i). 

(23) ASTM D1475–60 (Reapproved 

1980), 90, Standard Test Method for 

Density of Paint, Varnish Lacquer, and 

Related Products, IBR approved for 

§ 60.435(d)(1), Appendix A: Method 24, 

Section 6.1; and Method 24A, Sections 

6.5 and 7.1. 

(24) ASTM D1552–83, 95, 01, 

Standard Test Method for Sulfur in 

Petroleum Products (High-Temperature 

Method), IBR approved for 

§§ 60.106(j)(2), 60.335(b)(10)(i), and 

Appendix A: Method 19, Section 

12.5.2.2.3. 

(25) ASTM D1552–03, Standard Test 

Method for Sulfur in Petroleum 

Products (High-Temperature Method), 

IBR approved for § 60.4415(a)(1)(i). 

(26) ASTM D1826–77, 94, Standard 

Test Method for Calorific Value of Gases 

in Natural Gas Range by Continuous 

Recording Calorimeter, IBR approved 

for §§ 60.45(f)(5)(ii), 60.46(c)(2), 

60.296(b)(3), and Appendix A: Method 

19, Section 12.3.2.4. 

(27) ASTM D1835–87, 91, 97, 03a, 

Standard Specification for Liquefied 

Petroleum (LP) Gases, IBR approved for 

§§ 60.41Da of subpart Da of this part, 

60.41b of subpart Db of this part, and 

60.41c of subpart Dc of this part. 

(28) ASTM D1945–64, 76, 91, 96, 

Standard Method for Analysis of 

Natural Gas by Gas Chromatography, 

IBR approved for § 60.45(f)(5)(i). 

(29) ASTM D1946–77, 90 

(Reapproved 1994), Standard Method 

for Analysis of Reformed Gas by Gas 

Chromatography, IBR approved for 

§§ 60.18(f)(3), 60.45(f)(5)(i), 60.564(f)(1), 

60.614(e)(2)(ii), 60.614(e)(4), 

60.664(e)(2)(ii), 60.664(e)(4), 

60.704(d)(2)(ii), and 60.704(d)(4). 

(30) ASTM D2013–72, 86, Standard 

Method of Preparing Coal Samples for 

Analysis, IBR approved for Appendix A: 

Method 19, Section 12.5.2.1.3. 

(31) ASTM D2015–77 (Reapproved 

1978), 96, Standard Test Method for 

Gross Calorific Value of Solid Fuel by 

the Adiabatic Bomb Calorimeter, IBR 

approved for § 60.45(f)(5)(ii), 60.46(c)(2), 

and Appendix A: Method 19, Section 

12.5.2.1.3. 

(32) ASTM D2016–74, 83, Standard 

Test Methods for Moisture Content of 

Wood, IBR approved for Appendix A: 

Method 28, Section 16.1.1. 

(33) ASTM D2234–76, 96, 97b, 98, 

Standard Methods for Collection of a 

Gross Sample of Coal, IBR approved for 

Appendix A: Method 19, Section 

12.5.2.1.1. 

(34) ASTM D2369–81, 87, 90, 92, 93, 

95, Standard Test Method for Volatile 

Content of Coatings, IBR approved for 

Appendix A: Method 24, Section 6.2. 

(35) ASTM D2382–76, 88, Heat of 

Combustion of Hydrocarbon Fuels by 

Bomb Calorimeter (High-Precision 

Method), IBR approved for 

§§ 60.18(f)(3), 60.485(g)(6), 60.564(f)(3), 

60.614(e)(4), 60.664(e)(4), and 

60.704(d)(4). 

(36) ASTM D2504–67, 77, 88 

(Reapproved 1993), Noncondensable 

Gases in C3 and Lighter Hydrocarbon 

Products by Gas Chromatography, IBR 

approved for § 60.485(g)(5). 

(37) ASTM D2584–68 (Reapproved 

1985), 94, Standard Test Method for 

Ignition Loss of Cured Reinforced 

Resins, IBR approved for 

§ 60.685(c)(3)(i). 

(38) ASTM D2597–94 (Reapproved 

1999), Standard Test Method for 

Analysis of Demethanized Hydrocarbon 

Liquid Mixtures Containing Nitrogen 

and Carbon Dioxide by Gas 

Chromatography, IBR approved for 

§ 60.335(b)(9)(i). 

(39) ASTM D2622–87, 94, 98, 

Standard Test Method for Sulfur in 

Petroleum Products by Wavelength 

Dispersive X-Ray Fluorescence 

Spectrometry, IBR approved for 

§§ 60.106(j)(2) and 60.335(b)(10)(i). 

(40) ASTM D2622–05, Standard Test 

Method for Sulfur in Petroleum 

Products by Wavelength Dispersive XRay Fluorescence Spectrometry, IBR 

approved for § 60.4415(a)(1)(i). 

(41) ASTM D2879–83, 96, 97, Test 

Method for Vapor Pressure-Temperature 

Relationship and Initial Decomposition 

Temperature of Liquids by Isoteniscope, 

IBR approved for §§ 60.111b(f)(3), 

60.116b(e)(3)(ii), 60.116b(f)(2)(i), and 

60.485(e)(1). 

(42) ASTM D2880–78, 96, Standard 

Specification for Gas Turbine Fuel Oils, 

IBR approved for §§ 60.111(b), 

60.111a(b), and 60.335(d). 

(43) ASTM D2908–74, 91, Standard 

Practice for Measuring Volatile Organic 

Matter in Water by Aqueous-Injection 

Gas Chromatography, IBR approved for 

§ 60.564(j). 

(44) ASTM D2986–71, 78, 95a, 

Standard Method for Evaluation of Air, 

Assay Media by the Monodisperse DOP 

(Dioctyl Phthalate) Smoke Test, IBR 

approved for Appendix A: Method 5, 

Section 7.1.1; Method 12, Section 7.1.1; 

and Method 13A, Section 7.1.1.2. 

(45) ASTM D3173–73, 87, Standard 

Test Method for Moisture in the 


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Analysis Sample of Coal and Coke, IBR 

approved for Appendix A: Method 19, 

Section 12.5.2.1.3. 

(46) ASTM D3176–74, 89, Standard 

Method for Ultimate Analysis of Coal 

and Coke, IBR approved for 

§ 60.45(f)(5)(i) and Appendix A: Method 

19, Section 12.3.2.3. 

(47) ASTM D3177–75, 89, Standard 

Test Method for Total Sulfur in the 

Analysis Sample of Coal and Coke, IBR 

approved for Appendix A: Method 19, 

Section 12.5.2.1.3. 

(48) ASTM D3178–73 (Reapproved 

1979), 89, Standard Test Methods for 

Carbon and Hydrogen in the Analysis 

Sample of Coal and Coke, IBR approved 

for § 60.45(f)(5)(i). 

(49) ASTM D3246–81, 92, 96, 

Standard Test Method for Sulfur in 

Petroleum Gas by Oxidative 

Microcoulometry, IBR approved for 

§ 60.335(b)(10)(ii). 

(50) ASTM D3246–05, Standard Test 

Method for Sulfur in Petroleum Gas by 

Oxidative Microcoulometry, IBR 

approved for § 60.4415(a)(1)(ii). 

(51) ASTM D3270–73T, 80, 91, 95, 

Standard Test Methods for Analysis for 

Fluoride Content of the Atmosphere and 

Plant Tissues (Semiautomated Method), 

IBR approved for Appendix A: Method 

13A, Section 16.1. 

(52) ASTM D3286–85, 96, Standard 

Test Method for Gross Calorific Value of 

Coal and Coke by the Isoperibol Bomb 

Calorimeter, IBR approved for Appendix 

A: Method 19, Section 12.5.2.1.3. 

(53) ASTM D3370–76, 95a, Standard 

Practices for Sampling Water, IBR 

approved for § 60.564(j). 

(54) ASTM D3792–79, 91, Standard 

Test Method for Water Content of 

Water-Reducible Paints by Direct 

Injection into a Gas Chromatograph, IBR 

approved for Appendix A: Method 24, 

Section 6.3. 

(55) ASTM D4017–81, 90, 96a, 

Standard Test Method for Water in 

Paints and Paint Materials by the Karl 

Fischer Titration Method, IBR approved 

for Appendix A: Method 24, Section 6.4. 

(56) ASTM D4057–81, 95, Standard 

Practice for Manual Sampling of 

Petroleum and Petroleum Products, IBR 

approved for Appendix A: Method 19, 

Section 12.5.2.2.3. 

(57) ASTM D4057–95 (Reapproved 

2000), Standard Practice for Manual 

Sampling of Petroleum and Petroleum 

Products, IBR approved for 

§ 60.4415(a)(1). 

(58) ASTM D4084–82, 94, Standard 

Test Method for Analysis of Hydrogen 

Sulfide in Gaseous Fuels (Lead Acetate 

Reaction Rate Method), IBR approved 

for § 60.334(h)(1). 

(59) ASTM D4084–05, Standard Test 

Method for Analysis of Hydrogen 

Sulfide in Gaseous Fuels (Lead Acetate 

Reaction Rate Method), IBR approved 

for §§ 60.4360 and 60.4415(a)(1)(ii). 

(60) ASTM D4177–95, Standard 

Practice for Automatic Sampling of 

Petroleum and Petroleum Products, IBR 

approved for Appendix A: Method 19, 

Section 12.5.2.2.1. 

(61) ASTM D4177–95 (Reapproved 

2000), Standard Practice for Automatic 

Sampling of Petroleum and Petroleum 

Products, IBR approved for 

§ 60.4415(a)(1). 

(62) ASTM D4239–85, 94, 97, 

Standard Test Methods for Sulfur in the 

Analysis Sample of Coal and Coke 

Using High Temperature Tube Furnace 

Combustion Methods, IBR approved for 

Appendix A: Method 19, Section 

12.5.2.1.3. 

(63) ASTM D4294–02, Standard Test 

Method for Sulfur in Petroleum and 

Petroleum Products by EnergyDispersive X-Ray Fluorescence 

Spectrometry, IBR approved for 

§ 60.335(b)(10)(i). 

(64) ASTM D4294–03, Standard Test 

Method for Sulfur in Petroleum and 

Petroleum Products by EnergyDispersive X-Ray Fluorescence 

Spectrometry, IBR approved for 

§ 60.4415(a)(1)(i). 

(65) ASTM D4442–84, 92, Standard 

Test Methods for Direct Moisture 

Content Measurement in Wood and 

Wood-base Materials, IBR approved for 

Appendix A: Method 28, Section 16.1.1. 

(66) ASTM D4444–92, Standard Test 

Methods for Use and Calibration of 

Hand-Held Moisture Meters, IBR 

approved for Appendix A: Method 28, 

Section 16.1.1. 

(67) ASTM D4457–85 (Reapproved 

1991), Test Method for Determination of 

Dichloromethane and 1, 1, 1- 

Trichloroethane in Paints and Coatings 

by Direct Injection into a Gas 

Chromatograph, IBR approved for 

Appendix A: Method 24, Section 6.5. 

(68) ASTM D4468–85 (Reapproved 

2000), Standard Test Method for Total 

Sulfur in Gaseous Fuels by 

Hydrogenolysis and Rateometric 

Colorimetry, IBR approved for 

§§ 60.335(b)(10)(ii) and 60.4415(a)(1)(ii). 

(69) ASTM D4629–02, Standard Test 

Method for Trace Nitrogen in Liquid 

Petroleum Hydrocarbons by Syringe/ 

Inlet Oxidative Combustion and 

Chemiluminescence Detection, IBR 

approved for §§ 60.49b(e) and 

60.335(b)(9)(i). 

(70) ASTM D4809–95, Standard Test 

Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter (Precision Method), IBR 

approved for §§ 60.18(f)(3), 60.485(g)(6), 

60.564(f)(3), 60.614(d)(4), 60.664(e)(4), 

and 60.704(d)(4). 

(71) ASTM D4810–88 (Reapproved 

1999), Standard Test Method for 

Hydrogen Sulfide in Natural Gas Using 

Length of Stain Detector Tubes, IBR 

approved for §§ 60.4360 and 

60.4415(a)(1)(ii). 

(72) ASTM D5287–97 (Reapproved 

2002), Standard Practice for Automatic 

Sampling of Gaseous Fuels, IBR 

approved for § 60.4415(a)(1). 

(73) ASTM D5403–93, Standard Test 

Methods for Volatile Content of 

Radiation Curable Materials, IBR 

approved for Appendix A: Method 24, 

Section 6.6. 

(74) ASTM D5453–00, Standard Test 

Method for Determination of Total 

Sulfur in Light Hydrocarbons, Motor 

Fuels and Oils by Ultraviolet 

Fluorescence, IBR approved for 

§ 60.335(b)(10)(i). 

(75) ASTM D5453–05, Standard Test 

Method for Determination of Total 

Sulfur in Light Hydrocarbons, Motor 

Fuels and Oils by Ultraviolet 

Fluorescence, IBR approved for 

§ 60.4415(a)(1)(i). 

(76) ASTM D5504–01, Standard Test 

Method for Determination of Sulfur 

Compounds in Natural Gas and Gaseous 

Fuels by Gas Chromatography and 

Chemiluminescence, IBR approved for 

§§ 60.334(h)(1) and 60.4360. 

(77) ASTM D5762–02, Standard Test 

Method for Nitrogen in Petroleum and 

Petroleum Products by Boat-Inlet 

Chemiluminescence, IBR approved for 

§ 60.335(b)(9)(i). 

(78) ASTM D5865–98, Standard Test 

Method for Gross Calorific Value of Coal 

and Coke, IBR approved for 

§ 60.45(f)(5)(ii), 60.46(c)(2), and 

Appendix A: Method 19, Section 

12.5.2.1.3. 

(79) ASTM D6216–98, Standard 

Practice for Opacity Monitor 

Manufacturers to Certify Conformance 

with Design and Performance 

Specifications, IBR approved for 

Appendix B, Performance Specification 

1. 

(80) ASTM D6228–98, Standard Test 

Method for Determination of Sulfur 

Compounds in Natural Gas and Gaseous 

Fuels by Gas Chromatography and 

Flame Photometric Detection, IBR 

approved for § 60.334(h)(1). 

(81) ASTM D6228–98 (Reapproved 

2003), Standard Test Method for 

Determination of Sulfur Compounds in 

Natural Gas and Gaseous Fuels by Gas 

Chromatography and Flame Photometric 

Detection, IBR approved for §§ 60.4360 

and 60.4415. 

(82) ASTM D6348–03, Standard Test 

Method for Determination of Gaseous 

Compounds by Extractive Direct 

Interface Fourier Transform Infrared 


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(FTIR) Spectroscopy, IBR approved for 

table 7 of Subpart IIII of this part. 

(83) ASTM D6366–99, Standard Test 

Method for Total Trace Nitrogen and Its 

Derivatives in Liquid Aromatic 

Hydrocarbons by Oxidative Combustion 

and Electrochemical Detection, IBR 

approved for § 60.335(b)(9)(i). 

(84) ASTM D6522–00, Standard Test 

Method for Determination of Nitrogen 

Oxides, Carbon Monoxide, and Oxygen 

Concentrations in Emissions from 

Natural Gas-Fired Reciprocating 

Engines, Combustion Turbines, Boilers, 

and Process Heaters Using Portable 

Analyzers, IBR approved for § 60.335(a). 

(85) ASTM D6667–01, Standard Test 

Method for Determination of Total 

Volatile Sulfur in Gaseous 

Hydrocarbons and Liquefied Petroleum 

Gases by Ultraviolet Fluorescence, IBR 

approved for § 60.335(b)(10)(ii). 

(86) ASTM D6667–04, Standard Test 

Method for Determination of Total 

Volatile Sulfur in Gaseous 

Hydrocarbons and Liquefied Petroleum 

Gases by Ultraviolet Fluorescence, IBR 

approved for § 60.4415(a)(1)(ii). 

(87) ASTM D6784–02, Standard Test 

Method for Elemental, Oxidized, 

Particle-Bound and Total Mercury in 

Flue Gas Generated from Coal-Fired 

Stationary Sources (Ontario Hydro 

Method), IBR approved for Appendix B 

to part 60, Performance Specification 

12A, Section 8.6.2. 

(88) ASTM E168–67, 77, 92, General 

Techniques of Infrared Quantitative 

Analysis, IBR approved for 

§§ 60.593(b)(2) and 60.632(f). 

(89) ASTM E169–63, 77, 93, General 

Techniques of Ultraviolet Quantitative 

Analysis, IBR approved for 

§§ 60.593(b)(2) and 60.632(f). 

(90) ASTM E260–73, 91, 96, General 

Gas Chromatography Procedures, IBR 

approved for §§ 60.593(b)(2) and 

60.632(f). 

* * * * * 

(h) * * * 

(2) ASME PTC 4.1–1964 (Reaffirmed 

1991), Power Test Codes: Test Code for 

Steam Generating Units (with 1968 and 

1969 Addenda), IBR approved for 

§§ 60.46b of subpart Db of this part, 

60.58a(h)(6)(ii), 60.58b(i)(6)(ii), 

60.1320(a)(3) and 60.1810(a)(3). 

* * * * * 

Subpart D—[Amended] 

■ 4. Part 60 is amended by revising 

subpart D to read as follows: 

Subpart D—Standards of Performance for 

Fossil-Fuel-Fired Steam Generators for 

Which Construction Is Commenced After 

August 17, 1971 

Sec. 

60.40 Applicability and designation of 

affected facility. 

60.41 Definitions. 

60.42 Standard for particulate matter (PM). 

60.43 Standard for sulfur dioxide (SO2). 

60.44 Standard for nitrogen oxides (NOX). 

60.45 Emission and fuel monitoring. 

60.46 Test methods and procedures. 

Subpart D—Standards of Performance 

for Fossil-Fuel-Fired Steam Generators 

for Which Construction Is Commenced 

After August 17, 1971 

§ 60.40 Applicability and designation of 

affected facility. 

(a) The affected facilities to which the 

provisions of this subpart apply are: 

(1) Each fossil-fuel-fired steam 

generating unit of more than 73 

megawatts (MW) heat input rate (250 

million British thermal units per hour 

(MMBtu/hr)). 

(2) Each fossil-fuel and wood-residuefired steam generating unit capable of 

firing fossil fuel at a heat input rate of 

more than 73 MW (250 MMBtu/hr). 

(b) Any change to an existing fossilfuel-fired steam generating unit to 

accommodate the use of combustible 

materials, other than fossil fuels as 

defined in this subpart, shall not bring 

that unit under the applicability of this 

subpart. 

(c) Except as provided in paragraph 

(d) of this section, any facility under 

paragraph (a) of this section that 

commenced construction or 

modification after August 17, 1971, is 

subject to the requirements of this 

subpart. 

(d) The requirements of §§ 60.44 

(a)(4), (a)(5), (b) and (d), and 

60.45(f)(4)(vi) are applicable to lignitefired steam generating units that 

commenced construction or 

modification after December 22, 1976. 

(e) Any facility covered under subpart 

Da is not covered under this subpart. 

§ 60.41 Definitions. 

As used in this subpart, all terms not 

defined herein shall have the meaning 

given them in the Act, and in subpart A 

of this part. 

Boiler operating day means a 24-hour 

period between 12 midnight and the 

following midnight during which any 

fuel is combusted at any time in the 

steam-generating unit. It is not 

necessary for fuel to be combusted the 

entire 24-hour period. 

Coal means all solid fuels classified as 

anthracite, bituminous, subbituminous, 

or lignite by ASTM D388 (incorporated 

by reference, see § 60.17). 

Coal refuse means waste-products of 

coal mining, cleaning, and coal 

preparation operations (e.g. culm, gob, 

etc.) containing coal, matrix material, 

clay, and other organic and inorganic 

material. 

Fossil fuel means natural gas, 

petroleum, coal, and any form of solid, 

liquid, or gaseous fuel derived from 

such materials for the purpose of 

creating useful heat. 

Fossil fuel and wood residue-fired 

steam generating unit means a furnace 

or boiler used in the process of burning 

fossil fuel and wood residue for the 

purpose of producing steam by heat 

transfer. 

Fossil-fuel-fired steam generating unit 

means a furnace or boiler used in the 

process of burning fossil fuel for the 

purpose of producing steam by heat 

transfer. 

Wood residue means bark, sawdust, 

slabs, chips, shavings, mill trim, and 

other wood products derived from wood 

processing and forest management 

operations. 

§ 60.42 Standard for particulate matter 

(PM). 

(a) On and after the date on which the 

performance test required to be 

conducted by § 60.8 is completed, no 

owner or operator subject to the 

provisions of this subpart shall cause to 

be discharged into the atmosphere from 

any affected facility any gases that: 

(1) Contain PM in excess of 43 

nanograms per joule (ng/J) heat input 

(0.10 lb/MMBtu) derived from fossil fuel 

or fossil fuel and wood residue. 

(2) Exhibit greater than 20 percent 

opacity except for one six-minute period 

per hour of not more than 27 percent 

opacity. 

(b)(1) On or after December 28, 1979, 

no owner or operator shall cause to be 

discharged into the atmosphere from the 

Southwestern Public Service Company’s 

Harrington Station #1, in Amarillo, TX, 

any gases which exhibit greater than 35 

percent opacity, except that a maximum 

or 42 percent opacity shall be permitted 

for not more than 6 minutes in any 

hour. 

(2) Interstate Power Company shall 

not cause to be discharged into the 

atmosphere from its Lansing Station 

Unit No. 4 in Lansing, IA, any gases 

which exhibit greater than 32 percent 

opacity, except that a maximum of 39 

percent opacity shall be permitted for 

not more than six minutes in any hour. 

§ 60.43 Standard for sulfur dioxide (SO2). 

(a) Except as provided under 

paragraph (d) of this section, on and 

after the date on which the performance 

test required to be conducted by § 60.8 

is completed, no owner or operator 

subject to the provisions of this subpart 

shall cause to be discharged into the 

atmosphere from any affected facility 

any gases that contain SO2 in excess of: 


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32718 Federal Register / Vol. 72, No. 113 / Wednesday, June 13, 2007 / Rules and Regulations 

(1) 340 ng/J heat input (0.80 lb/ 

MMBtu) derived from liquid fossil fuel 

or liquid fossil fuel and wood residue. 

(2) 520 ng/J heat input (1.2 lb/MMBtu) 

derived from solid fossil fuel or solid 

fossil fuel and wood residue, except as 

provided in paragraph (e) of this 

section. 

(b) Except as provided under 

paragraph (d) of this section, when 

different fossil fuels are burned 

simultaneously in any combination, the 

applicable standard (in ng/J) shall be 

determined by proration using the 

following formula: 

PS y z

y z SO2

340 520 = +

+

 () ()

( )

Where: 

PSSO2 = Prorated standard for SO2 when 

burning different fuels simultaneously, 

in ng/J heat input derived from all fossil 

fuels or from all fossil fuels and wood 

residue fired; 

y = Percentage of total heat input derived 

from liquid fossil fuel; and 

z = Percentage of total heat input derived 

from solid fossil fuel. 

(c) Compliance shall be based on the 

total heat input from all fossil fuels 

burned, including gaseous fuels. 

(d) As an alternate to meeting the 

requirements of paragraphs (a) and (b) of 

this section, an owner or operator can 

petition the Administrator (in writing) 

to comply with § 60.43Da(i)(3) of 

subpart Da of this part or comply with 

§ 60.42b(k) of subpart Db of this part, as 

applicable to the affected source. If the 

Administrator grants the petition, the 

source will from then on (unless the 

unit is modified or reconstructed in the 

future) have to comply with the 

requirements in § 60.43Da(i)(3) of 

subpart Da of this part or § 60.42b(k) of 

subpart Db of this part, as applicable to 

the affected source. 

(e) Units 1 and 2 (as defined in 

appendix G of this part) at the Newton 

Power Station owned or operated by the 

Central Illinois Public Service Company 

will be in compliance with paragraph 

(a)(2) of this section if Unit 1 and Unit 

2 individually comply with paragraph 

(a)(2) of this section or if the combined 

emission rate from Units 1 and 2 does 

not exceed 470 ng/J (1.1 lb/MMBtu) 

combined heat input to Units 1 and 2. 

§ 60.44 Standard for nitrogen oxides 

(NOX). 

(a) Except as provided under 

paragraph (e) of this section, on and 

after the date on which the performance 

test required to be conducted by § 60.8 

is completed, no owner or operator 

subject to the provisions of this subpart 

shall cause to be discharged into the 

atmosphere from any affected facility 

any gases that contain NOX, expressed 

as NO2 in excess of: 

(1) 86 ng/J heat input (0.20 lb/MMBtu) 

derived from gaseous fossil fuel. 

(2) 129 ng/J heat input (0.30 lb/ 

MMBtu) derived from liquid fossil fuel, 

liquid fossil fuel and wood residue, or 

gaseous fossil fuel and wood residue. 

(3) 300 ng/J heat input (0.70 lb/ 

MMBtu) derived from solid fossil fuel or 

solid fossil fuel and wood residue 

(except lignite or a solid fossil fuel 

containing 25 percent, by weight, or 

more of coal refuse). 

(4) 260 ng/J heat input (0.60 lb 

MMBtu) derived from lignite or lignite 

and wood residue (except as provided 

under paragraph (a)(5) of this section). 

(5) 340 ng/J heat input (0.80 lb 

MMBtu) derived from lignite which is 

mined in North Dakota, South Dakota, 

or Montana and which is burned in a 

cyclone-fired unit. 

(b) Except as provided under 

paragraphs (c), (d), and (e) of this 

section, when different fossil fuels are 

burned simultaneously in any 

combination, the applicable standard (in 

ng/J) is determined by proration using 

the following formula: 

PS xy z

wxyz NOX = ++ ++++

w ( ) () ( ) ( )

( )

260 86 130 300

Where: 

PSNOx = Prorated standard for NOX when 

burning different fuels simultaneously, 

in ng/J heat input derived from all fossil 

fuels fired or from all fossil fuels and 

wood residue fired; 

w = Percentage of total heat input derived 

from lignite; 

x = Percentage of total heat input derived 

from gaseous fossil fuel; 

y = Percentage of total heat input derived 

from liquid fossil fuel; and 

z = Percentage of total heat input derived 

from solid fossil fuel (except lignite). 

(c) When a fossil fuel containing at 

least 25 percent, by weight, of coal 

refuse is burned in combination with 

gaseous, liquid, or other solid fossil fuel 

or wood residue, the standard for NOX

does not apply. 

(d) Except as provided under 

paragraph (e) of this section, cyclonefired units which burn fuels containing 

at least 25 percent of lignite that is 

mined in North Dakota, South Dakota, 

or Montana remain subject to paragraph 

(a)(5) of this section regardless of the 

types of fuel combusted in combination 

with that lignite. 

(e) As an alternate to meeting the 

requirements of paragraphs (a), (b), and 

(d) of this section, an owner or operator 

can petition the Administrator (in 

writing) to comply with § 60.44Da(e)(3) 

of subpart Da of this part. If the 

Administrator grants the petition, the 

source will from then on (unless the 

unit is modified or reconstructed in the 

future) have to comply with the 

requirements in § 60.44Da(e)(3) of 

subpart Da of this part. 

§ 60.45 Emissions and fuel monitoring. 

(a) Each owner or operator shall 

install, calibrate, maintain, and operate 

continuous emissions monitoring 

systems (CEMS) for measuring the 

opacity of emissions, SO2 emissions, 

NOX emissions, and either oxygen (O2) 

or carbon dioxide (CO2) except as 

provided in paragraph (b) of this 

section. 

(b) Certain of the CEMS requirements 

under paragraph (a) of this section do 

not apply to owners or operators under 

the following conditions: 

(1) For a fossil-fuel-fired steam 

generator that burns only gaseous fossil 

fuel and that does not use postcombustion technology to reduce 

emissions of SO2 or PM, CEMS for 

measuring the opacity of emissions and 

SO2 emissions are not required. 

(2) For a fossil-fuel-fired steam 

generator that does not use a flue gas 

desulfurization device, a CEMS for 

measuring SO2 emissions is not required 

if the owner or operator monitors SO2

emissions by fuel sampling and 

analysis. 

(3) Notwithstanding § 60.13(b), 

installation of a CEMS for NOX may be 

delayed until after the initial 

performance tests under § 60.8 have 

been conducted. If the owner or 

operator demonstrates during the 

performance test that emissions of NOX

are less than 70 percent of the 

applicable standards in § 60.44, a CEMS 

for measuring NOX emissions is not 

required. If the initial performance test 

results show that NOX emissions are 

greater than 70 percent of the applicable 

standard, the owner or operator shall 

install a CEMS for NOX within one year 

after the date of the initial performance 


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Federal Register / Vol. 72, No. 113 / Wednesday, June 13, 2007 / Rules and Regulations 32719 

tests under § 60.8 and comply with all 

other applicable monitoring 

requirements under this part. 

(4) If an owner or operator does not 

install any CEMS for sulfur oxides and 

NOX, as provided under paragraphs 

(b)(1) and (b)(3) or paragraphs (b)(2) and 

(b)(3) of this section a CEMS for 

measuring either O2 or CO2 is not 

required. 

(5) An owner or operator may petition 

the Administrator (in writing) to install 

a PM CEMS as an alternative to the 

CEMS for monitoring opacity emissions. 

(6) A CEMS for measuring the opacity 

of emissions is not required for a fossil 

fuel-fired steam generator that does not 

use post-combustion technology (except 

a wet scrubber) for reducing PM, SO2, or 

carbon monoxide (CO) emissions, burns 

only gaseous fuels or fuel oils that 

contain less than or equal to 0.30 weight 

percent sulfur, and is operated such that 

emissions of CO to the atmosphere from 

the affected source are maintained at 

levels less than or equal to 0.15 lb/ 

MMBtu on a boiler operating day 

average basis. Owners and operators of 

affected sources electing to comply with 

this paragraph must demonstrate 

compliance according to the procedures 

specified in paragraphs (b)(6)(i) through 

(iv) of this section. 

(i) You must monitor CO emissions 

using a CEMS according to the 

procedures specified in paragraphs 

(b)(6)(i)(A) through (D) of this section. 

(A) The CO CEMS must be installed, 

certified, maintained, and operated 

according to the provisions in 

§ 60.58b(i)(3) of subpart Eb of this part. 

(B) Each 1-hour CO emissions average 

is calculated using the data points 

generated by the CO CEMS expressed in 

parts per million by volume corrected to 

3 percent oxygen (dry basis). 

(C) At a minimum, valid 1-hour CO 

emissions averages must be obtained for 

at least 90 percent of the operating 

hours on a 30-day rolling average basis. 

At least two data points per hour must 

be used to calculate each 1-hour 

average. 

(D) Quarterly accuracy determinations 

and daily calibration drift tests for the 

CO CEMS must be performed in 

accordance with procedure 1 in 

appendix F of this part. 

(ii) You must calculate the 1-hour 

average CO emissions levels for each 

boiler operating day by multiplying the 

average hourly CO output concentration 

measured by the CO CEMS times the 

corresponding average hourly flue gas 

flow rate and divided by the 

corresponding average hourly heat input 

to the affected source. The 24-hour 

average CO emission level is determined 

by calculating the arithmetic average of 

the hourly CO emission levels 

computed for each boiler operating day. 

(iii) You must evaluate the preceding 

24-hour average CO emission level each 

boiler operating day excluding periods 

of affected source startup, shutdown, or 

malfunction. If the 24-hour average CO 

emission level is greater than 0.15 lb/ 

MMBtu, you must initiate investigation 

of the relevant equipment and control 

systems within 24 hours of the first 

discovery of the high emission incident 

and, take the appropriate corrective 

action as soon as practicable to adjust 

control settings or repair equipment to 

reduce the 24-hour average CO emission 

level to 0.15 lb/MMBtu or less. 

(iv) You must record the CO 

measurements and calculations 

performed according to paragraph (b)(6) 

of this section and any corrective 

actions taken. The record of corrective 

action taken must include the date and 

time during which the 24-hour average 

CO emission level was greater than 0.15 

lb/MMBtu, and the date, time, and 

description of the corrective action. 

(c) For performance evaluations under 

§ 60.13(c) and calibration checks under 

§ 60.13(d), the following procedures 

shall be used: 

(1) Methods 6, 7, and 3B of appendix 

A of this part, as applicable, shall be 

used for the performance evaluations of 

SO2 and NOX continuous monitoring 

systems. Acceptable alternative methods 

for Methods 6, 7, and 3B of appendix A 

of this part are given in § 60.46(d). 

(2) Sulfur dioxide or nitric oxide, as 

applicable, shall be used for preparing 

calibration gas mixtures under 

Performance Specification 2 of 

appendix B to this part. 

(3) For affected facilities burning 

fossil fuel(s), the span value for a 

continuous monitoring system 

measuring the opacity of emissions shall 

be 80, 90, or 100 percent. For a 

continuous monitoring system 

measuring sulfur oxides or NOX the 

span value shall be determined using 

one of the following procedures: 

(i) Except as provided under 

paragraph (c)(3)(ii) of this section, SO2

and NOX span values shall be 

determined as follows: 

Fossil fuel 

In parts per million 

Span value for SO2 Span value for NOX

Gas ............................................................................................................................................. (1) ................................. 500. 

Liquid .......................................................................................................................................... 1,000 ............................ 500. 

Solid ............................................................................................................................................ 1,500 ............................ 1,000. 

Combinations .............................................................................................................................. 1,000y + 1,500z ........... 500 (x + y) + 1,000z. 

1 Not applicable. 

Where: 

x = Fraction of total heat input derived from 

gaseous fossil fuel; 

y = Fraction of total heat input derived from 

liquid fossil fuel; and 

z = Fraction of total heat input derived from 

solid fossil fuel. 

(ii) As an alternative to meeting the 

requirements of paragraph (c)(3)(i) of 

this section, the owner or operator of an 

affected facility may elect to use the SO2

and NOX span values determined 

according to sections 2.1.1 and 2.1.2 in 

appendix A to part 75 of this chapter. 

(4) All span values computed under 

paragraph (c)(3)(i) of this section for 

burning combinations of fossil fuels 

shall be rounded to the nearest 500 

ppm. Span values that are computed 

under paragraph (c)(3)(ii) of this section 

shall be rounded off according to the 

applicable procedures in section 2 of 

appendix A to part 75 of this chapter. 

(5) For a fossil-fuel-fired steam 

generator that simultaneously burns 

fossil fuel and nonfossil fuel, the span 

value of all CEMS shall be subject to the 

Administrator’s approval. 

(d) [Reserved] 

(e) For any CEMS installed under 

paragraph (a) of this section, the 

following conversion procedures shall 

be used to convert the continuous 

monitoring data into units of the 

applicable standards (ng/J, lb/MMBtu): 

(1) When a CEMS for measuring O2 is 

selected, the measurement of the 

pollutant concentration and O2

concentration shall each be on a 

consistent basis (wet or dry). Alternative 

procedures approved by the 

Administrator shall be used when 

measurements are on a wet basis. When 

measurements are on a dry basis, the 


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32720 Federal Register / Vol. 72, No. 113 / Wednesday, June 13, 2007 / Rules and Regulations 

following conversion procedure shall be 

used: 

E CF

O = ( ) −

















20 9

20 9 2

.

. %

Where E, C, F, and %O2 are determined 

under paragraph (f) of this section. 

(2) When a CEMS for measuring CO2

is selected, the measurement of the 

pollutant concentration and CO2

concentration shall each be on a 

consistent basis (wet or dry) and the 

following conversion procedure shall be 

used: 

E CF

CO = c





 



 100

% 2

Where E, C, Fc and %CO2 are determined 

under paragraph (f) of this section. 

(f) The values used in the equations 

under paragraphs (e)(1) and (2) of this 

section are derived as follows: 

(1) E = pollutant emissions, ng/J (lb/ 

MMBtu). 

(2) C = pollutant concentration, ng/ 

dscm (lb/dscf), determined by 

multiplying the average concentration 

(ppm) for each one-hour period by 4.15 

× 104 M ng/dscm per ppm (2.59 × 10¥9

M lb/dscf per ppm) where 

M = pollutant molecular weight, g/gmole (lb/lb-mole). M = 64.07 for SO2

and 46.01 for NOX. 

(3) %O2, %CO2 = O2 or CO2 volume 

(expressed as percent), determined with 

equipment specified under paragraph 

(a) of this section. 

(4) F, Fc = a factor representing a ratio 

of the volume of dry flue gases 

generated to the calorific value of the 

fuel combusted (F), and a factor 

representing a ratio of the volume of 

CO2 generated to the calorific value of 

the fuel combusted (Fc), respectively. 

Values of F and Fc are given as follows: 

(i) For anthracite coal as classified 

according to ASTM D388 (incorporated 

by reference, see § 60.17), F = 2,723 × 

10¥17 dscm/J (10,140 dscf/MMBtu) and 

Fc = 0.532 × 10¥17 scm CO2/J (1,980 scf 

CO2/MMBtu). 

(ii) For subbituminous and 

bituminous coal as classified according 

to ASTM D388 (incorporated by 

reference, see § 60.17), F = 2.637 × 10¥7

dscm/J (9,820 dscf/MMBtu) and Fc = 

0.486 × 10¥7 scm CO2/J (1,810 scf CO2/ 

MMBtu). 

(iii) For liquid fossil fuels including 

crude, residual, and distillate oils, F = 

2.476 × 10¥7 dscm/J (9,220 dscf/ 

MMBtu) and Fc = 0.384 × 10¥7 scm 

CO2/J (1,430 scf CO2/MMBtu). 

(iv) For gaseous fossil fuels, F = 2.347 

× 10¥7 dscm/J (8,740 dscf/MMBtu). For 

natural gas, propane, and butane fuels, 

Fc = 0.279 × 10¥7 scm CO2/J (1,040 scf 

CO2/MMBtu) for natural gas, 0.322 × 

10¥7 scm CO2/J (1,200 scf CO2/MMBtu) 

for propane, and 0.338 × 10¥7 scm CO2/ 

J (1,260 scf CO2/MMBtu) for butane. 

(v) For bark F = 2.589 × 10¥7 dscm/ 

J (9,640 dscf/MMBtu) and Fc = 0.500 × 

10¥7 scm CO2/J (1,840 scf CO2/MMBtu). 

For wood residue other than bark F = 

2.492 × 10¥7 dscm/J (9,280 dscf/ 

MMBtu) and Fc = 0.494 × 10¥7 scm 

CO2/J (1,860 scf CO2/MMBtu). 

(vi) For lignite coal as classified 

according to ASTM D388 (incorporated 

by reference, see § 60.17), F = 2.659 × 

10¥7 dscm/J (9,900 dscf/MMBtu) and Fc

= 0.516 × 10¥7 scm CO2/J (1,920 scf 

CO2/MMBtu). 

(5) The owner or operator may use the 

following equation to determine an F 

factor (dscm/J or dscf/MMBtu) on a dry 

basis (if it is desired to calculate F on 

a wet basis, consult the Administrator) 

or Fc factor (scm CO2/J, or scf CO2/ 

MMBtu) on either basis in lieu of the F 

or Fc factors specified in paragraph (f)(4) 

of this section: 

F = − − 10 6 [. . . . 227 2 35 6 8 7 28 7 (%H) + 95.5 (%C) + (%S) + (%N) (%O)]

GCV

(%C)

GCV (SI units)

 (%H) + (%C)

F

F

c = ×

=

−

−

2 0 10

10 3 64 1 53

5

6

.

[. . + (%S) + (%N) (%O)]

GCV (English units)

0 57 0 14 0 46

20 0

.. .

.

−

Fc = (%C)

GCV (SI units)

 (%C)

GCV (English units)

Fc = 321 10 × 3

(i) %H, %C, %S, %N, and %O are 

content by weight of hydrogen, carbon, 

sulfur, nitrogen, and O2 (expressed as 

percent), respectively, as determined on 

the same basis as GCV by ultimate 

analysis of the fuel fired, using ASTM 

D3178 or D3176 (solid fuels), or 

computed from results using ASTM 

D1137, D1945, or D1946 (gaseous fuels) 

as applicable. (These five methods are 

incorporated by reference, see § 60.17.) 

(ii) GVC is the gross calorific value 

(kJ/kg, Btu/lb) of the fuel combusted 

determined by the ASTM test methods 

D2015 or D5865 for solid fuels and 

D1826 for gaseous fuels as applicable. 

(These three methods are incorporated 

by reference, see § 60.17.) 

(iii) For affected facilities which fire 

both fossil fuels and nonfossil fuels, the 

F or Fc value shall be subject to the 

Administrator’s approval. 

(6) For affected facilities firing 

combinations of fossil fuels or fossil 

fuels and wood residue, the F or Fc 

factors determined by paragraphs (f)(4) 

or (f)(5) of this section shall be prorated 

in accordance with the applicable 

formula as follows: 

F X F or F X F i i

i

n

c ic i i

n

= = ( ) = =

∑ ∑ 1 1

Where: 


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Federal Register / Vol. 72, No. 113 / Wednesday, June 13, 2007 / Rules and Regulations 32721 

Xi = Fraction of total heat input derived from 

each type of fuel (e.g. natural gas, 

bituminous coal, wood residue, etc.); 

Fi or (Fc)i = Applicable F or Fc factor for each 

fuel type determined in accordance with 

paragraphs (f)(4) and (f)(5) of this 

section; and 

n = Number of fuels being burned in 

combination. 

(g) Excess emission and monitoring 

system performance reports shall be 

submitted to the Administrator 

semiannually for each six-month period 

in the calendar year. All semiannual 

reports shall be postmarked by the 30th 

day following the end of each six-month 

period. Each excess emission and MSP 

report shall include the information 

required in § 60.7(c). Periods of excess 

emissions and monitoring systems (MS) 

downtime that shall be reported are 

defined as follows: 

(1) Opacity. Excess emissions are 

defined as any six-minute period during 

which the average opacity of emissions 

exceeds 20 percent opacity, except that 

one six-minute average per hour of up 

to 27 percent opacity need not be 

reported. 

(i) For sources subject to the opacity 

standard of § 60.42(b)(1), excess 

emissions are defined as any six-minute 

period during which the average opacity 

of emissions exceeds 35 percent opacity, 

except that one six-minute average per 

hour of up to 42 percent opacity need 

not be reported. 

(ii) For sources subject to the opacity 

standard of § 60.42(b)(2), excess 

emissions are defined as any six-minute 

period during which the average opacity 

of emissions exceeds 32 percent opacity, 

except that one six-minute average per 

hour of up to 39 percent opacity need 

not be reported. 

(2) Sulfur dioxide. Excess emissions 

for affected facilities are defined as: 

(i) Any three-hour period during 

which the average emissions (arithmetic 

average of three contiguous one-hour 

periods) of SO2 as measured by a CEMS 

exceed the applicable standard under 

§ 60.43, or 

(ii) Any 30 operating day period 

during which the average emissions 

(arithmetic average of all one-hour 

periods during the 30 operating days) of 

SO2 as measured by a CEMS exceed the 

applicable standard under § 60.43. 

Facilities complying with the 30-day 

SO2 standard shall use the most current 

associated SO2 compliance and 

monitoring requirements in §§ 60.48Da 

and 60.49Da of subpart Da of this part. 

(3) Nitrogen oxides. Excess emissions 

for affected facilities using a CEMS for 

measuring NOX are defined as: 

(i) Any three-hour period during 

which the average emissions (arithmetic 

average of three contiguous one-hour 

periods) exceed the applicable 

standards under § 60.44, or 

(ii) Any 30 operating day period 

during which the average emissions 

(arithmetic average of all one-hour 

periods during the 30 operating days) of 

NOX as measured by a CEMS exceed the 

applicable standard under § 60.43. 

Facilities complying with the 30-day 

NOX standard shall use the most current 

associated NOX compliance and 

monitoring requirements in §§ 60.48Da 

and 60.49Da of subpart Da of this part. 

(4) Particulate matter. Excess 

emissions for affected facilities using a 

CEMS for measuring PM are defined as 

any boiler operating day period during 

which the average emissions (arithmetic 

average of all operating one-hour 

periods) exceed the applicable 

standards under § 60.43. Affected 

facilities using PM CEMS in lieu of a 

CEMS for monitoring opacity emissions 

must follow the most current applicable 

compliance and monitoring provisions 

in §§ 60.48Da and 60.49Da of subpart Da 

of this part. 

§ 60.46 Test methods and procedures. 

(a) In conducting the performance 

tests required in § 60.8, and subsequent 

performance tests as requested by the 

EPA Administrator, the owner or 

operator shall use as reference methods 

and procedures the test methods in 

appendix A of this part or other 

methods and procedures as specified in 

this section, except as provided in 

§ 60.8(b). Acceptable alternative 

methods and procedures are given in 

paragraph (d) of this section. 

(b) The owner or operator shall 

determine compliance with the PM, 

SO2, and NOX standards in §§ 60.42, 

60.43, and 60.44 as follows: 

(1) The emission rate (E) of PM, SO2, 

or NOX shall be computed for each run 

using the following equation: 

E CF

O = d

( ) −

















20 9

20 9 2

.

. %

Where: 

E = Emission rate of pollutant, ng/J (1b/ 

million Btu); 

C = Concentration of pollutant, ng/dscm (1b/ 

dscf); 

%O2 = O2 concentration, percent dry basis; 

and 

Fd = Factor as determined from Method 19 

of appendix A of this part. 

(2) Method 5 of appendix A of this 

part shall be used to determine the PM 

concentration (C) at affected facilities 

without wet flue-gas-desulfurization 

(FGD) systems and Method 5B of 

appendix A of this part shall be used to 

determine the PM concentration (C) 

after FGD systems. 

(i) The sampling time and sample 

volume for each run shall be at least 60 

minutes and 0.85 dscm (30 dscf). The 

probe and filter holder heating systems 

in the sampling train shall be set to 

provide an average gas temperature of 

160±14 °C (320±25 °F). 

(ii) The emission rate correction 

factor, integrated or grab sampling and 

analysis procedure of Method 3B of 

appendix A of this part shall be used to 

determine the O2 concentration (%O2). 

The O2 sample shall be obtained 

simultaneously with, and at the same 

traverse points as, the particulate 

sample. If the grab sampling procedure 

is used, the O2 concentration for the run 

shall be the arithmetic mean of the 

sample O2 concentrations at all traverse 

points. 

(iii) If the particulate run has more 

than 12 traverse points, the O2 traverse 

points may be reduced to 12 provided 

that Method 1 of appendix A of this part 

is used to locate the 12 O2 traverse 

points. 

(3) Method 9 of appendix A of this 

part and the procedures in § 60.11 shall 

be used to determine opacity. 

(4) Method 6 of appendix A of this 

part shall be used to determine the SO2

concentration. 

(i) The sampling site shall be the same 

as that selected for the particulate 

sample. The sampling location in the 

duct shall be at the centroid of the cross 

section or at a point no closer to the 

walls than 1 m (3.28 ft). The sampling 

time and sample volume for each 

sample run shall be at least 20 minutes 

and 0.020 dscm (0.71 dscf). Two 

samples shall be taken during a 1-hour 

period, with each sample taken within 

a 30-minute interval. 

(ii) The emission rate correction 

factor, integrated sampling and analysis 

procedure of Method 3B of appendix A 

of this part shall be used to determine 

the O2 concentration (%O2). The O2

sample shall be taken simultaneously 

with, and at the same point as, the SO2

sample. The SO2 emission rate shall be 

computed for each pair of SO2 and O2

samples. The SO2 emission rate (E) for 

each run shall be the arithmetic mean of 

the results of the two pairs of samples. 

(5) Method 7 of appendix A of this 

part shall be used to determine the NOX

concentration. 

(i) The sampling site and location 

shall be the same as for the SO2 sample. 

Each run shall consist of four grab 

samples, with each sample taken at 

about 15-minute intervals. 

(ii) For each NOX sample, the 

emission rate correction factor, grab 

sampling and analysis procedure of 


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Method 3B of appendix A of this part 

shall be used to determine the O2

concentration (%O2). The sample shall 

be taken simultaneously with, and at the 

same point as, the NOX sample. 

(iii) The NOX emission rate shall be 

computed for each pair of NOX and O2

samples. The NOX emission rate (E) for 

each run shall be the arithmetic mean of 

the results of the four pairs of samples. 

(c) When combinations of fossil fuels 

or fossil fuel and wood residue are fired, 

the owner or operator (in order to 

compute the prorated standard as 

shown in §§ 60.43(b) and 60.44(b)) shall 

determine the percentage (w, x, y, or z) 

of the total heat input derived from each 

type of fuel as follows: 

(1) The heat input rate of each fuel 

shall be determined by multiplying the 

gross calorific value of each fuel fired by 

the rate of each fuel burned. 

(2) ASTM Methods D2015, or D5865 

(solid fuels), D240 (liquid fuels), or 

D1826 (gaseous fuels) (all of these 

methods are incorporated by reference, 

see § 60.17) shall be used to determine 

the gross calorific values of the fuels. 

The method used to determine the 

calorific value of wood residue must be 

approved by the Administrator. 

(3) Suitable methods shall be used to 

determine the rate of each fuel burned 

during each test period, and a material 

balance over the steam generating 

system shall be used to confirm the rate. 

(d) The owner or operator may use the 

following as alternatives to the reference 

methods and procedures in this section 

or in other sections as specified: 

(1) The emission rate (E) of PM, SO2

and NOX may be determined by using 

the Fc factor, provided that the 

following procedure is used: 

(i) The emission rate (E) shall be 

computed using the following equation: 

E CF

CO = c





 



 100

% 2

Where: 

E = Emission rate of pollutant, ng/J (lb/ 

MMBtu); 

C = Concentration of pollutant, ng/dscm (lb/ 

dscf); 

%CO2 = CO2 concentration, percent dry 

basis; and 

Fc = Factor as determined in appropriate 

sections of Method 19 of appendix A of 

this part. 

(ii) If and only if the average Fc factor 

in Method 19 of appendix A of this part 

is used to calculate E and either E is 

from 0.97 to 1.00 of the emission 

standard or the relative accuracy of a 

continuous emission monitoring system 

is from 17 to 20 percent, then three runs 

of Method 3B of appendix A of this part 

shall be used to determine the O2 and 

CO2 concentration according to the 

procedures in paragraph (b)(2)(ii), (4)(ii), 

or (5)(ii) of this section. Then if Fo

(average of three runs), as calculated 

from the equation in Method 3B of 

appendix A of this part, is more than ±3 

percent than the average Fo value, as 

determined from the average values of 

Fd and Fc in Method 19 of appendix A 

of this part, i.e., Foa = 0.209 (Fda/Fca), 

then the following procedure shall be 

followed: 

(A) When Fo is less than 0.97 Foa, then 

E shall be increased by that proportion 

under 0.97 Foa, e.g., if Fo is 0.95 Foa, E 

shall be increased by 2 percent. This 

recalculated value shall be used to 

determine compliance with the 

emission standard. 

(B) When Fo is less than 0.97 Foa and 

when the average difference (d) between 

the continuous monitor minus the 

reference methods is negative, then E 

shall be increased by that proportion 

under 0.97 Foa, e.g., if Fo is 0.95 Foa, E 

shall be increased by 2 percent. This 

recalculated value shall be used to 

determine compliance with the relative 

accuracy specification. 

(C) When Fo is greater than 1.03 Foa

and when the average difference d is 

positive, then E shall be decreased by 

that proportion over 1.03 Foa, e.g., if Fo

is 1.05 Foa, E shall be decreased by 2 

percent. This recalculated value shall be 

used to determine compliance with the 

relative accuracy specification. 

(2) For Method 5 or 5B of appendix 

A of this part, Method 17 of appendix 

A of this part may be used at facilities 

with or without wet FGD systems if the 

stack gas temperature at the sampling 

location does not exceed an average 

temperature of 16 0°C (320 °F). The 

procedures of sections 2.1 and 2.3 of 

Method 5B of appendix A of this part 

may be used with Method 17 of 

appendix A of this part only if it is used 

after wet FGD systems. Method 17 of 

appendix A of this part shall not be 

used after wet FGD systems if the 

effluent gas is saturated or laden with 

water droplets. 

(3) Particulate matter and SO2 may be 

determined simultaneously with the 

Method 5 of appendix A of this part 

train provided that the following 

changes are made: 

(i) The filter and impinger apparatus 

in sections 2.1.5 and 2.1.6 of Method 8 

of appendix A of this part is used in 

place of the condenser (section 2.1.7) of 

Method 5 of appendix A of this part. 

(ii) All applicable procedures in 

Method 8 of appendix A of this part for 

the determination of SO2 (including 

moisture) are used: 

(4) For Method 6 of appendix A of 

this part, Method 6C of appendix A of 

this part may be used. Method 6A of 

appendix A of this part may also be 

used whenever Methods 6 and 3B of 

appendix A of this part data are 

specified to determine the SO2 emission 

rate, under the conditions in paragraph 

(d)(1) of this section. 

(5) For Method 7 of appendix A of 

this part, Method 7A, 7C, 7D, or 7E of 

appendix A of this part may be used. If 

Method 7C, 7D, or 7E of appendix A of 

this part is used, the sampling time for 

each run shall be at least 1 hour and the 

integrated sampling approach shall be 

used to determine the O2 concentration 

(%O2) for the emission rate correction 

factor. 

(6) For Method 3 of appendix A of 

this part, Method 3A or 3B of appendix 

A of this part may be used. 

(7) For Method 3B of appendix A of 

this part, Method 3A of appendix A of 

this part may be used. 

Subpart Da—[Amended] 

■ 4a. Subpart Da is revised as follows: 

Subpart Da—Standards of Performance for 

Electric Utility Steam Generating Units for 

Which Construction is Commenced After 

September 18, 1978 

Sec. 

60.40Da Applicability and designation of 

affected facility. 

60.41Da Definitions. 

60.42Da Standard for particulate matter 

(PM). 

60.43Da Standard for sulfur dioxide (SO2). 

60.44Da Standard for nitrogen oxides 

(NOX). 

60.45Da Standard for mercury (Hg). 

60.46Da [Reserved] 

60.47Da Commercial demonstration permit. 

60.48Da Compliance provisions. 

60.49Da Emission monitoring. 

60.50Da Compliance determination 

procedures and methods. 

60.51Da Reporting requirements. 

60.52Da Recordkeeping requirements. 

Subpart Da—Standards of 

Performance for Electric Utility Steam 

Generating Units for Which 

Construction is Commenced After 

September 18, 1978 

§ 60.40Da Applicability and designation of 

affected facility. 

(a) The affected facility to which this 

subpart applies is each electric utility 

steam generating unit: 

(1) That is capable of combusting 

more than 73 megawatts (MW) (250 

million British thermal units per hour 

(MMBtu/hr) heat input of fossil fuel 

(either alone or in combination with any 

other fuel); and 

(2) For which construction, 

modification, or reconstruction is 

commenced after September 18, 1978. 


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(b) Combined cycle gas turbines (both 

the stationary combustion turbine and 

any associated duct burners) are subject 

to this part and not subject to subpart 

GG or KKKK of this part if: 

(1) The combined cycle gas turbine is 

capable of combusting more than 73 

MW (250 MMBtu/hr) heat input of fossil 

fuel (either alone or in combination 

with any other fuel); and 

(2) The combined cycle gas turbine is 

designed and intended to burn fuels 

containing 50 percent (by heat input) or 

more solid-derived fuel not meeting the 

definition of natural gas on a 12-month 

rolling average basis; and 

(3) The combined cycle gas turbine 

commenced construction, modification, 

or reconstruction after February 28, 

2005. 

(4) This subpart will continue to 

apply to all other electric utility 

combined cycle gas turbines that are 

capable of combusting more than 73 

MW (250 MMBtu/hr) heat input of fossil 

fuel in the heat recovery steam 

generator. If the heat recovery steam 

generator is subject to this subpart and 

the stationary combustion turbine is 

subject to either subpart GG or KKKK of 

this part, only emissions resulting from 

combustion of fuels in the steamgenerating unit are subject to this 

subpart. (The stationary combustion 

turbine emissions are subject to subpart 

GG or KKKK, as applicable, of this part). 

(c) Any change to an existing fossilfuel-fired steam generating unit to 

accommodate the use of combustible 

materials, other than fossil fuels, shall 

not bring that unit under the 

applicability of this subpart. 

(d) Any change to an existing steam 

generating unit originally designed to 

fire gaseous or liquid fossil fuels, to 

accommodate the use of any other fuel 

(fossil or nonfossil) shall not bring that 

unit under the applicability of this 

subpart. 

§ 60.41Da Definitions. 

As used in this subpart, all terms not 

defined herein shall have the meaning 

given them in the Act and in subpart A 

of this part. 

Anthracite means coal that is 

classified as anthracite according to the 

American Society of Testing and 

Materials in ASTM D388 (incorporated 

by reference, see § 60.17). 

Available purchase power means the 

lesser of the following: 

(a) The sum of available system 

capacity in all neighboring companies. 

(b) The sum of the rated capacities of 

the power interconnection devices 

between the principal company and all 

neighboring companies, minus the sum 

of the electric power load on these 

interconnections. 

(c) The rated capacity of the power 

transmission lines between the power 

interconnection devices and the electric 

generating units (the unit in the 

principal company that has the 

malfunctioning flue gas desulfurization 

system and the unit(s) in the 

neighboring company supplying 

replacement electrical power) less the 

electric power load on these 

transmission lines. 

Available system capacity means the 

capacity determined by subtracting the 

system load and the system emergency 

reserves from the net system capacity. 

Biomass means plant materials and 

animal waste. 

Bituminous coal means coal that is 

classified as bituminous according to 

the American Society of Testing and 

Materials in ASTM D388 (incorporated 

by reference, see § 60.17). 

Boiler operating day for units 

constructed, reconstructed, or modified 

on or before February 28, 2005, means 

a 24-hour period during which fossil 

fuel is combusted in a steam-generating 

unit for the entire 24 hours. For units 

constructed, reconstructed, or modified 

after February 28, 2005, boiler operating 

day means a 24-hour period between 12 

midnight and the following midnight 

during which any fuel is combusted at 

any time in the steam-generating unit. It 

is not necessary for fuel to be combusted 

the entire 24-hour period. 

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 (not 

meeting the definition of natural gas), 

coal-oil mixtures, and coal-water 

mixtures are included in this definition 

for the purposes of this subpart. 

Coal-fired electric utility steam 

generating unit means an electric utility 

steam generating unit that burns coal, 

coal refuse, or a synthetic gas derived 

from coal either exclusively, in any 

combination together, or in any 

combination with other fuels in any 

amount. 

Coal refuse means waste products of 

coal mining, physical coal cleaning, and 

coal preparation operations (e.g. culm, 

gob, etc.) containing coal, matrix 

material, clay, and other organic and 

inorganic material. 

Cogeneration, also known as 

‘‘combined heat and power,’’ means a 

steam-generating unit that 

simultaneously produces both electric 

(or mechanical) and useful thermal 

energy from the same primary energy 

source. 

Combined cycle gas turbine means a 

stationary turbine combustion system 

where heat from the turbine exhaust 

gases is recovered by a steam generating 

unit. 

Dry flue gas desulfurization 

technology or dry FGD means a sulfur 

dioxide control system that is located 

downstream of the steam generating 

unit and removes sulfur oxides (SO2) 

from the combustion gases of the steam 

generating unit by contacting the 

combustion gases with an alkaline 

reagent and water, whether introduced 

separately or as a premixed slurry or 

solution and forming a dry powder 

material. This definition includes 

devices where the dry powder material 

is subsequently converted to another 

form. Alkaline slurries or solutions used 

in dry FGD technology include, but are 

not limited to, lime and sodium. 

Duct burner means a device that 

combusts fuel and that is placed in the 

exhaust duct from another source, such 

as a stationary gas turbine, internal 

combustion engine, kiln, etc., to allow 

the firing of additional fuel to heat the 

exhaust gases before the exhaust gases 

enter a heat recovery steam generating 

unit. 

Electric utility combined cycle gas 

turbine means any combined cycle gas 

turbine used for electric generation that 

is constructed for the purpose of 

supplying more than one-third of its 

potential electric output capacity and 

more than 25 MW net-electrical output 

to any utility power distribution system 

for sale. Any steam distribution system 

that is constructed for the purpose of 

providing steam to a steam electric 

generator that would produce electrical 

power for sale is also considered in 

determining the electrical energy output 

capacity of the affected facility. 

Electric utility company means the 

largest interconnected organization, 

business, or governmental entity that 

generates electric power for sale (e.g., a 

holding company with operating 

subsidiary companies). 

Electric utility steam-generating unit 

means any steam electric generating 

unit that is constructed for the purpose 

of supplying more than one-third of its 

potential electric output capacity and 

more than 25 MW net-electrical output 

to any utility power distribution system 

for sale. Also, any steam supplied to a 

steam distribution system for the 

purpose of providing steam to a steamelectric generator that would produce 

electrical energy for sale is considered 

in determining the electrical energy 

output capacity of the affected facility. 


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Electrostatic precipitator or ESP 

means an add-on air pollution control 

device used to capture particulate 

matter (PM) by charging the particles 

using an electrostatic field, collecting 

the particles using a grounded collecting 

surface, and transporting the particles 

into a hopper. 

Emergency condition means that 

period of time when: 

(1) The electric generation output of 

an affected facility with a 

malfunctioning flue gas desulfurization 

system cannot be reduced or electrical 

output must be increased because: 

(i) All available system capacity in the 

principal company interconnected with 

the affected facility is being operated, 

and 

(ii) All available purchase power 

interconnected with the affected facility 

is being obtained, or 

(2) The electric generation demand is 

being shifted as quickly as possible from 

an affected facility with a 

malfunctioning flue gas desulfurization 

system to one or more electrical 

generating units held in reserve by the 

principal company or by a neighboring 

company, or 

(3) An affected facility with a 

malfunctioning flue gas desulfurization 

system becomes the only available unit 

to maintain a part or all of the principal 

company’s system emergency reserves 

and the unit is operated in spinning 

reserve at the lowest practical electric 

generation load consistent with not 

causing significant physical damage to 

the unit. If the unit is operated at a 

higher load to meet load demand, an 

emergency condition would not exist 

unless the conditions under paragraph 

(1) of this definition apply. 

Emission limitation means any 

emissions limit or operating limit. 

Emission rate period means any 

calendar month included in a 12-month 

rolling average period. 

Federally enforceable means all 

limitations and conditions that are 

enforceable by the Administrator, 

including the requirements of 40 CFR 

parts 60 and 61, requirements within 

any applicable State implementation 

plan, and any permit requirements 

established under 40 CFR 52.21 or 

under 40 CFR 51.18 and 51.24. 

Fossil fuel means natural gas, 

petroleum, coal, and any form of solid, 

liquid, or gaseous fuel derived from 

such material for the purpose of creating 

useful heat. 

Gaseous fuel means any fuel derived 

from coal or petroleum that is present as 

a gas at standard conditions and 

includes, but is not limited to, refinery 

fuel gas, process gas, coke-oven gas, 

synthetic gas, and gasified coal. 

Gross output means the gross useful 

work performed by the steam generated 

and, for an IGCC electric utility steam 

generating unit, the fuel burned in 

stationary combustion turbines. For a 

unit generating only electricity, the 

gross useful work performed is the gross 

electrical output from the unit’s turbine/ 

generator sets. For a cogeneration unit, 

the gross useful work performed is the 

gross electrical or mechanical output 

plus 75 percent of the useful thermal 

output measured relative to ISO 

conditions that is not used to generate 

additional electrical or mechanical 

output (i.e., steam delivered to an 

industrial process). 

24-hour period means the period of 

time between 12:01 a.m. and 12:00 

midnight. 

Integrated gasification combined 

cycle electric utility steam generating 

unit or IGCC electric utility steam 

generating unit means a coal-fired 

electric utility steam generating unit 

that burns a synthetic gas derived from 

coal in a combined-cycle gas turbine. No 

coal is directly burned in the unit 

during operation. 

Interconnected means that two or 

more electric generating units are 

electrically tied together by a network of 

power transmission lines, and other 

power transmission equipment. 

ISO conditions means a temperature 

of 288 Kelvin, a relative humidity of 60 

percent, and a pressure of 101.3 

kilopascals. 

Lignite means coal that is classified as 

lignite A or B according to the American 

Society of Testing and Materials in 

ASTM D388 (incorporated by reference, 

see § 60.17). 

Natural gas means: 

(1) A naturally occurring mixture of 

hydrocarbon and nonhydrocarbon gases 

found in geologic formations beneath 

the earth’s surface, of which the 

principal constituent is methane; or 

(2) Liquid petroleum gas, as defined 

by the American Society of Testing and 

Materials in ASTM D1835 (incorporated 

by reference, see § 60.17); or 

(3) A mixture of hydrocarbons that 

maintains a gaseous state at ISO 

conditions. Additionally, natural gas 

must either be composed of at least 70 

percent methane by volume or have a 

gross calorific value between 34 and 43 

megajoules (MJ) per standard cubic 

meter (910 and 1,150 Btu per standard 

cubic foot). 

Neighboring company means any one 

of those electric utility companies with 

one or more electric power 

interconnections to the principal 

company and which have 

geographically adjoining service areas. 

Net-electric output means the gross 

electric sales to the utility power 

distribution system minus purchased 

power on a calendar year basis. 

Net system capacity means the sum of 

the net electric generating capability 

(not necessarily equal to rated capacity) 

of all electric generating equipment 

owned by an electric utility company 

(including steam generating units, 

internal combustion engines, gas 

turbines, nuclear units, hydroelectric 

units, and all other electric generating 

equipment) plus firm contractual 

purchases that are interconnected to the 

affected facility that has the 

malfunctioning flue gas desulfurization 

system. The electric generating 

capability of equipment under multiple 

ownership is prorated based on 

ownership unless the proportional 

entitlement to electric output is 

otherwise established by contractual 

arrangement. 

Noncontinental area means the State 

of Hawaii, the Virgin Islands, Guam, 

American Samoa, the Commonwealth of 

Puerto Rico, or the Northern Mariana 

Islands. 

Petroleum means crude oil or 

petroleum or a fuel derived from crude 

oil or petroleum, including, but not 

limited to, distillate oil, residual oil, and 

petroleum coke. 

Potential combustion concentration 

means the theoretical emissions 

(nanograms per joule (ng/J), lb/MMBtu 

heat input) that would result from 

combustion of a fuel in an uncleaned 

state without emission control systems) 

and: 

(1) For particulate matter (PM) is: 

(i) 3,000 ng/J (7.0 lb/MMBtu) heat 

input for solid fuel; and 

(ii) 73 ng/J (0.17 lb/MMBtu) heat 

input for liquid fuels. 

(2) For sulfur dioxide (SO2) is 

determined under § 60.50Da(c). 

(3) For nitrogen oxides (NOX) is: 

(i) 290 ng/J (0.67 lb/MMBtu) heat 

input for gaseous fuels; 

(ii) 310 ng/J (0.72 lb/MMBtu) heat 

input for liquid fuels; and 

(iii) 990 ng/J (2.30 lb/MMBtu) heat 

input for solid fuels. 

Potential electrical output capacity 

means 33 percent of the maximum 

design heat input capacity of the steam 

generating unit, divided by 3,413 Btu/ 

KWh, divided by 1,000 kWh/MWh, and 

multiplied by 8,760 hr/yr (e.g., a steam 

generating unit with a 100 MW (340 

MMBtu/hr) fossil-fuel heat input 

capacity would have a 289,080 MWh 12 

month potential electrical output 

capacity). For electric utility combined 

cycle gas turbines the potential 

electrical output capacity is determined 

on the basis of the fossil-fuel firing 


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capacity of the steam generator 

exclusive of the heat input and 

electrical power contribution by the gas 

turbine. 

Principal company means the electric 

utility company or companies which 

own the affected facility. 

Resource recovery unit means a 

facility that combusts more than 75 

percent non-fossil fuel on a quarterly 

(calendar) heat input basis. 

Responsible official means 

responsible official as defined in 40 CFR 

70.2. 

Solid-derived fuel means any solid, 

liquid, or gaseous fuel derived from 

solid fuel for the purpose of creating 

useful heat and includes, but is not 

limited to, solvent refined coal, liquified 

coal, synthetic gas, gasified coal, 

gasified petroleum coke, gasified 

biomass, and gasified tire derived fuel. 

Spare flue gas desulfurization system 

module means a separate system of SO2

emission control equipment capable of 

treating an amount of flue gas equal to 

the total amount of flue gas generated by 

an affected facility when operated at 

maximum capacity divided by the total 

number of nonspare flue gas 

desulfurization modules in the system. 

Spinning reserve means the sum of 

the unutilized net generating capability 

of all units of the electric utility 

company that are synchronized to the 

power distribution system and that are 

capable of immediately accepting 

additional load. The electric generating 

capability of equipment under multiple 

ownership is prorated based on 

ownership unless the proportional 

entitlement to electric output is 

otherwise established by contractual 

arrangement. 

Steam generating unit means any 

furnace, boiler, or other device used for 

combusting fuel for the purpose of 

producing steam (including fossil-fuelfired steam generators associated with 

combined cycle gas turbines; nuclear 

steam generators are not included). 

Subbituminous coal means coal that 

is classified as subbituminous A, B, or 

C according to the American Society of 

Testing and Materials in ASTM D388 

(incorporated by reference, see § 60.17). 

System emergency reserves means an 

amount of electric generating capacity 

equivalent to the rated capacity of the 

single largest electric generating unit in 

the electric utility company (including 

steam generating units, internal 

combustion engines, gas turbines, 

nuclear units, hydroelectric units, and 

all other electric generating equipment) 

which is interconnected with the 

affected facility that has the 

malfunctioning flue gas desulfurization 

system. The electric generating 

capability of equipment under multiple 

ownership is prorated based on 

ownership unless the proportional 

entitlement to electric output is 

otherwise established by contractual 

arrangement. 

System load means the entire electric 

demand of an electric utility company’s 

service area interconnected with the 

affected facility that has the 

malfunctioning flue gas desulfurization 

system plus firm contractual sales to 

other electric utility companies. Sales to 

other electric utility companies (e.g., 

emergency power) not on a firm 

contractual basis may also be included 

in the system load when no available 

system capacity exists in the electric 

utility company to which the power is 

supplied for sale. 

Wet flue gas desulfurization 

technology or wet FGD means a SO2

control system that is located 

downstream of the steam generating 

unit and removes sulfur oxides from the 

combustion gases of the steam 

generating unit by contacting the 

combustion gases with an alkaline 

slurry or solution and forming a liquid 

material. This definition applies to 

devices where the aqueous liquid 

material product of this contact is 

subsequently converted to other forms. 

Alkaline reagents used in wet FGD 

technology include, but are not limited 

to, lime, limestone, and sodium. 

§ 60.42Da Standard for particulate matter 

(PM). 

(a) 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, no owner or 

operator subject to the provisions of this 

subpart shall cause to be discharged into 

the atmosphere from any affected 

facility for which construction, 

reconstruction, or modification 

commenced before or on February 28, 

2005, any gases that contain PM in 

excess of: 

(1) 13 ng/J (0.03 lb/MMBtu) heat input 

derived from the combustion of solid, 

liquid, or gaseous fuel; 

(2) 1 percent of the potential 

combustion concentration (99 percent 

reduction) when combusting solid fuel; 

and 

(3) 30 percent of potential combustion 

concentration (70 percent reduction) 

when combusting liquid fuel. 

(b) On and after the date the initial 

PM performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator subject to the provisions of this 

subpart shall cause to be discharged into 

the atmosphere from any affected 

facility any gases which exhibit greater 

than 20 percent opacity (6-minute 

average), except for one 6-minute period 

per hour of not more than 27 percent 

opacity. 

(c) Except as provided in paragraph 

(d) 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, no owner or operator of an affected 

facility that commenced construction, 

reconstruction, or modification after 

February 28, 2005 shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain PM in excess of either: 

(1) 18 ng/J (0.14 lb/MWh) gross energy 

output; or 

(2) 6.4 ng/J (0.015 lb/MMBtu) heat 

input derived from the combustion of 

solid, liquid, or gaseous fuel. 

(d) As an alternative to meeting the 

requirements of paragraph (c) of this 

section, the owner or operator of an 

affected facility for which construction, 

reconstruction, or modification 

commenced after February 28, 2005, 

may elect to meet the requirements of 

this paragraph. 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, no owner or operator of an affected 

facility shall cause to be discharged into 

the atmosphere from that affected 

facility for which construction, 

reconstruction, or modification 

commenced after February 28, 2005, any 

gases that contain PM in excess of: 

(1) 13 ng/J (0.03 lb/MMBtu) heat input 

derived from the combustion of solid, 

liquid, or gaseous fuel, and 

(2) 0.1 percent of the combustion 

concentration determined according to 

the procedure in § 60.48Da(o)(5) (99.9 

percent reduction) for an affected 

facility for which construction or 

reconstruction commenced after 

February 28, 2005 when combusting 

solid, liquid, or gaseous fuel, or 

(3) 0.2 percent of the combustion 

concentration determined according to 

the procedure in § 60.48Da(o)(5) (99.8 

percent reduction) for an affected 

facility for which modification 

commenced after February 28, 2005 

when combusting solid, liquid, or 

gaseous fuel. 

§ 60.43Da Standard for sulfur dioxide 

(SO2). 

(a) 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, no owner or 

operator subject to the provisions of this 

subpart shall cause to be discharged into 

the atmosphere from any affected 

facility which combusts solid fuel or 


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solid-derived fuel and for which 

construction, reconstruction, or 

modification commenced before or on 

February 28, 2005, except as provided 

under paragraphs (c), (d), (f) or (h) of 

this section, any gases that contain SO2

in excess of: 

(1) 520 ng/J (1.20 lb/MMBtu) heat 

input and 10 percent of the potential 

combustion concentration (90 percent 

reduction); or 

(2) 30 percent of the potential 

combustion concentration (70 percent 

reduction), when emissions are less 

than 260 ng/J (0.60 lb/MMBtu) heat 

input. 

(b) 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, no owner or 

operator subject to the provisions of this 

subpart shall cause to be discharged into 

the atmosphere from any affected 

facility which combusts liquid or 

gaseous fuels (except for liquid or 

gaseous fuels derived from solid fuels 

and as provided under paragraphs (e) or 

(h) of this section) and for which 

construction, reconstruction, or 

modification commenced before or on 

February 28, 2005, any gases that 

contain SO2 in excess of: 

(1) 340 ng/J (0.80 lb/MMBtu) heat 

input and 10 percent of the potential 

combustion concentration (90 percent 

reduction); or 

(2) 100 percent of the potential 

combustion concentration (zero percent 

reduction) when emissions are less than 

86 ng/J (0.20 lb/MMBtu) heat input. 

(c) 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, no owner or 

operator subject to the provisions of this 

subpart shall cause to be discharged into 

the atmosphere from any affected 

facility which combusts solid solvent 

refined coal (SRC–I) any gases that 

contain SO2 in excess of 520 ng/J (1.20 

lb/MMBtu) heat input and 15 percent of 

the potential combustion concentration 

(85 percent reduction) except as 

provided under paragraph (f) of this 

section; compliance with the emission 

limitation is determined on a 30-day 

rolling average basis and compliance 

with the percent reduction requirement 

is determined on a 24-hour basis. 

(d) Sulfur dioxide emissions are 

limited to 520 ng/J (1.20 lb/MMBtu) 

heat input from any affected facility 

which: 

(1) Combusts 100 percent anthracite; 

(2) Is classified as a resource recovery 

unit; or 

(3) Is located in a noncontinental area 

and combusts solid fuel or solid-derived 

fuel. 

(e) Sulfur dioxide emissions are 

limited to 340 ng/J (0.80 lb/MMBtu) 

heat input from any affected facility 

which is located in a noncontinental 

area and combusts liquid or gaseous 

fuels (excluding solid-derived fuels). 

(f) The emission reduction 

requirements under this section do not 

apply to any affected facility that is 

operated under an SO2 commercial 

demonstration permit issued by the 

Administrator in accordance with the 

provisions of § 60.47Da. 

(g) Compliance with the emission 

limitation and percent reduction 

requirements under this section are both 

determined on a 30-day rolling average 

basis except as provided under 

paragraph (c) of this section. 

(h) When different fuels are 

combusted simultaneously, the 

applicable standard is determined by 

proration using the following formula: 

(1) If emissions of SO2 to the 

atmosphere are greater than 260 ng/J 

(0.60 lb/MMBtu) heat input 

E x y s s = and P + = ( ) % 340 520

100

10

(2) If emissions of SO2 to the 

atmosphere are equal to or less than 260 

ng/J (0.60 lb/MMBtu) heat input: 

E x y and P x y s s = + = ( ) + % 340 520 ( )

100

10 30

100

Where: 

Es = Prorated SO2 emission limit (ng/J heat 

input); 

%Ps = Percentage of potential SO2 emission 

allowed; 

x = Percentage of total heat input derived 

from the combustion of liquid or gaseous 

fuels (excluding solid-derived fuels); and 

y = Percentage of total heat input derived 

from the combustion of solid fuel 

(including solid-derived fuels). 

(i) Except as provided in paragraphs 

(j) and (k) 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, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification 

commenced after February 28, 2005 

shall cause to be discharged into the 

atmosphere from that affected facility, 

any gases that contain SO2 in excess of 

the applicable emission limitation 

specified in paragraphs (i)(1) through (3) 

of this section. 

(1) For an affected facility for which 

construction commenced after February 

28, 2005, any gases that contain SO2 in 

excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output on a 30-day rolling average basis; 

or 

(ii) 5 percent of the potential 

combustion concentration (95 percent 

reduction) on a 30-day rolling average 

basis. 

(2) For an affected facility for which 

reconstruction commenced after 

February 28, 2005, any gases that 

contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output on a 30-day rolling average basis; 

(ii) 65 ng/J (0.15 lb/MMBtu) heat 

input on a 30-day rolling average basis; 

or 

(iii) 5 percent of the potential 

combustion concentration (95 percent 

reduction) on a 30-day rolling average 

basis. 

(3) For an affected facility for which 

modification commenced after February 

28, 2005, any gases that contain SO2 in 

excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output on a 30-day rolling average basis; 

(ii) 65 ng/J (0.15 lb/MMBtu) heat 

input on a 30-day rolling average basis; 

or 

(iii) 10 percent of the potential 

combustion concentration (90 percent 

reduction) on a 30-day rolling average 

basis. 

(j) 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, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification 

commenced after February 28, 2005, 

and that burns 75 percent or more (by 

heat input) coal refuse on a 12-month 

rolling average basis, shall caused to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain SO2 in excess of the applicable 

emission limitation specified in 

paragraphs (j)(1) through (3) of this 

section. 

(1) For an affected facility for which 

construction commenced after February 


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28, 2005, any gases that contain SO2 in 

excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output on a 30-day rolling average basis; 

or 

(ii) 6 percent of the potential 

combustion concentration (94 percent 

reduction) on a 30-day rolling average 

basis. 

(2) For an affected facility for which 

reconstruction commenced after 

February 28, 2005, any gases that 

contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output on a 30-day rolling average basis; 

(ii) 65 ng/J (0.15 lb/MMBtu) heat 

input on a 30-day rolling average basis; 

or 

(iii) 6 percent of the potential 

combustion concentration (94 percent 

reduction) on a 30-day rolling average 

basis. 

(3) For an affected facility for which 

modification commenced after February 

28, 2005, any gases that contain SO2 in 

excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output on a 30-day rolling average basis; 

(ii) 65 ng/J (0.15 lb/MMBtu) heat 

input on a 30-day rolling average basis; 

or 

(iii) 10 percent of the potential 

combustion concentration (90 percent 

reduction) on a 30-day rolling average 

basis. 

(k) 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, no owner or 

operator of an affected facility located in 

a noncontinental area that commenced 

construction, reconstruction, or 

modification commenced after February 

28, 2005, shall cause to be discharged 

into the atmosphere from that affected 

facility any gases that contain SO2 in 

excess of the applicable emission 

limitation specified in paragraphs (k)(1) 

and (2) of this section. 

(1) For an affected facility that burns 

solid or solid-derived fuel, the owner or 

operator shall not cause to be 

discharged into the atmosphere any 

gases that contain SO2 in excess of 520 

ng/J (1.2 lb/MMBtu) heat input on a 30- 

day rolling average basis. 

(2) For an affected facility that burns 

other than solid or solid-derived fuel, 

the owner or operator shall not cause to 

be discharged into the atmosphere any 

gases that contain SO2 in excess of if the 

affected facility or 230 ng/J (0.54 lb/ 

MMBtu) heat input on a 30-day rolling 

average basis. 

§ 60.44Da Standard for nitrogen oxides 

(NOX). 

(a) 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, no owner or 

operator subject to the provisions of this 

subpart shall cause to be discharged into 

the atmosphere from any affected 

facility, except as provided under 

paragraphs (b), (d), (e), and (f) of this 

section, any gases that contain NOX

(expressed as NO2) in excess of the 

following emission limits, based on a 

30-day rolling average basis, except as 

provided under § 60.48Da(j)(1): 

(1) NOX emission limits. 

Fuel type 

Emission limit for 

heat input 

ng/J lb/MMBtu 

Gaseous fuels: 

Coal-derived fuels ............................................................................................................................................................. 210 0.50 

All other fuels .................................................................................................................................................................... 86 0.20 

Liquid fuels: 

Coal-derived fuels ............................................................................................................................................................. 210 0.50 

Shale oil ............................................................................................................................................................................ 210 0.50 

All other fuels .................................................................................................................................................................... 130 0.30 

Solid fuels: 

Coal-derived fuels ............................................................................................................................................................. 210 0.50 

Any fuel containing more than 25%, by weight, coal refuse ........................................................................................... (1) (1)

Any fuel containing more than 25%, by weight, lignite if the lignite is mined in North Dakota, South Dakota, or Montana, and is combusted in a slag tap furnace 2 ............................................................................................................ 340 0.80 

Any fuel containing more than 25%, by weight, lignite not subject to the 340 ng/J heat input emission limit 2 ............. 260 0.60 

Subbituminous coal .......................................................................................................................................................... 210 0.50 

Bituminous coal ................................................................................................................................................................ 260 0.60 

Anthracite coal .................................................................................................................................................................. 260 0.60 

All other fuels .................................................................................................................................................................... 260 0.60 

1Exempt from NOX standards and NOX monitoring requirements. 2 Any fuel containing less than 25%, by weight, lignite is not prorated but its percentage is added to the percentage of the predominant fuel. 

(2) NOX reduction requirement. 

Fuel type 

Percent reduction of potential 

combustion 

concentration 

Gaseous fuels ................... 25 

Liquid fuels ....................... 30 

Solid fuels ......................... 65 

(b) The emission limitations under 

paragraph (a) of this section do not 

apply to any affected facility which is 

combusting coal-derived liquid fuel and 

is operating under a commercial 

demonstration permit issued by the 

Administrator in accordance with the 

provisions of § 60.47Da. 

(c) Except as provided under 

paragraphs (d), (e), and (f) of this 

section, when two or more fuels are 

combusted simultaneously, the 

applicable standard is determined by 

proration using the following formula: 

E wxyzv n= ( ) 86 130 210 260 340 ++++

100

Where: 

En = Applicable standard for NOX when 

multiple fuels are combusted 

simultaneously (ng/J heat input); 

w = Percentage of total heat input derived 

from the combustion of fuels subject to 

the 86 ng/J heat input standard; 

x = Percentage of total heat input derived 

from the combustion of fuels subject to 

the 130 ng/J heat input standard; 

y = Percentage of total heat input derived 

from the combustion of fuels subject to 

the 210 ng/J heat input standard; 

z = Percentage of total heat input derived 

from the combustion of fuels subject to 

the 260 ng/J heat input standard; and 

v = Percentage of total heat input delivered 

from the combustion of fuels subject to 

the 340 ng/J heat input standard. 

(d)(1) On and after the date on which 

the initial performance test is completed 


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or required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that commenced construction after July 

9, 1997, but before or on February 28, 

2005 shall cause to be discharged into 

the atmosphere any gases that contain 

NOX (expressed as NO2) in excess of 200 

ng/J (1.6 lb/MWh) gross energy output, 

based on a 30-day rolling average basis, 

except as provided under § 60.48Da(k). 

(2) 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, no owner or 

operator of affected facility for which 

reconstruction commenced after July 9, 

1997, but before or on February 28, 2005 

shall cause to be discharged into the 

atmosphere any gases that contain NOX

(expressed as NO2) in excess of 65 ng/ 

J (0.15 lb/MMBtu) heat input, based on 

a 30-day rolling average basis. 

(e) Except for an IGCC electric utility 

steam generating unit meeting the 

requirements of 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, no 

owner or operator of an affected facility 

that commenced construction, 

reconstruction, or modification after 

February 28, 2005 shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain NOX (expressed as NO2) in 

excess of the applicable emission 

limitation specified in paragraphs (e)(1) 

through (3) of this section. 

(1) For an affected facility for which 

construction commenced after February 

28, 2005, the owner or operator shall not 

cause to be discharged into the 

atmosphere any gases that contain NOX

(expressed as NO2) in excess of 130 ng/ 

J (1.0 lb/MWh) gross energy output on 

a 30-day rolling average basis, except as 

provided under § 60.48Da(k). 

(2) For an affected facility for which 

reconstruction commenced after 

February 28, 2005, the owner or 

operator shall not cause to be 

discharged into the atmosphere any 

gases that contain NOX (expressed as 

NO2) in excess of either: 

(i) 130 ng/J (1.0 lb/MWh) gross energy 

output on a 30-day rolling average basis; 

or 

(ii) 47 ng/J (0.11 lb/MMBtu) heat 

input on a 30-day rolling average basis. 

(3) For an affected facility for which 

modification commenced after February 

28, 2005, the owner or operator shall not 

cause to be discharged into the 

atmosphere any gases that contain NOX

(expressed as NO2) in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output on a 30-day rolling average basis; 

or 

(ii) 65 ng/J (0.15 lb/MMBtu) heat 

input on a 30-day rolling average basis. 

(f) 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 of an IGCC electric utility 

steam generating unit subject to the 

provisions of this subpart and for which 

construction, reconstruction, or 

modification commenced after February 

28, 2005, shall meet the requirements 

specified in paragraphs (f)(1) through (3) 

of this section. 

(1) Except as provided for in 

paragraphs (f)(2) and (3) of this section, 

the owner or operator shall not cause to 

be discharged into the atmosphere any 

gases that contain NOX (expressed as 

NO2) in excess of 130 ng/J (1.0 lb/MWh) 

gross energy output on a 30-day rolling 

average basis. 

(2) When burning liquid fuel 

exclusively or in combination with 

solid-derived fuel such that the liquid 

fuel contributes 50 percent or more of 

the total heat input to the combined 

cycle combustion turbine, the owner or 

operator shall not cause to be 

discharged into the atmosphere any 

gases that contain NOX (expressed as 

NO2) in excess of 190 ng/J (1.5 lb/MWh) 

gross energy output on a 30-day rolling 

average basis. 

(3) In cases when during a 30-day 

rolling average compliance period 

liquid fuel is burned in such a manner 

to meet the conditions in paragraph 

(f)(2) of this section for only a portion 

of the clock hours in the 30-day period, 

the owner or operator shall not cause to 

be discharged into the atmosphere any 

gases that contain NOX (expressed as 

NO2) in excess of the computed 

weighted-average emissions limit based 

on the proportion of gross energy output 

(in MWh) generated during the 

compliance period for each of emissions 

limits in paragraphs (f)(1) and (2) of this 

section. 

§ 60.45Da Standard for mercury (Hg). 

(a) For each coal-fired electric utility 

steam generating unit other than an 

IGCC electric utility steam generating 

unit, 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, no owner or 

operator subject to the provisions of this 

subpart shall cause to be discharged into 

the atmosphere from any affected 

facility for which construction, 

modification, or reconstruction 

commenced after January 30, 2004, any 

gases that contain mercury (Hg) 

emissions in excess of each Hg 

emissions limit in paragraphs (a)(1) 

through (5) of this section that applies 

to you. The Hg emissions limits in 

paragraphs (a)(1) through (5) of this 

section are based on a 12-month rolling 

average basis using the procedures in 

§ 60.50Da(h). 

(1) For each coal-fired electric utility 

steam generating unit that burns only 

bituminous coal, you must not 

discharge into the atmosphere any gases 

from a new affected source that contain 

Hg in excess of 20 × 10¥6 pound per 

megawatt hour (lb/MWh) or 0.020 lb/ 

gigawatt-hour (GWh) on an output basis. 

The International System of Units (SI) 

equivalent is 0.0025 ng/J. 

(2) For each coal-fired electric utility 

steam generating unit that burns only 

subbituminous coal: 

(i) If your unit is located in a countylevel geographical area receiving greater 

than 25 inches per year (in/yr) mean 

annual precipitation, based on the most 

recent publicly available U.S. 

Department of Agriculture 30-year data, 

you must not discharge into the 

atmosphere any gases from a new 

affected source that contain Hg in excess 

of 66 × 10¥6 lb/MWh or 0.066 lb/GWh 

on an output basis. The SI equivalent is 

0.0083 ng/J. 

(ii) If your unit is located in a countylevel geographical area receiving less 

than or equal to 25 in/yr mean annual 

precipitation, based on the most recent 

publicly available U.S. Department of 

Agriculture 30-year data, you must not 

discharge into the atmosphere any gases 

from a new affected source that contain 

Hg in excess of 97 × 10¥6 lb/MWh or 

0.097 lb/GWh on an output basis. The 

SI equivalent is 0.0122 ng/J. 

(3) For each coal-fired electric utility 

steam generating unit that burns only 

lignite, you must not discharge into the 

atmosphere any gases from a new 

affected source that contain Hg in excess 

of 175 × 10¥6 lb/MWh or 0.175 lb/GWh 

on an output basis. The SI equivalent is 

0.0221 ng/J. 

(4) For each coal-burning electric 

utility steam generating unit that burns 

only coal refuse, you must not discharge 

into the atmosphere any gases from a 

new affected source that contain Hg in 

excess of 16 × 10¥6 lb/MWh or 0.016 lb/ 

GWh on an output basis. The SI 

equivalent is 0.0020 ng/J. 

(5) For each coal-fired electric utility 

steam generating unit that burns a blend 

of coals from different coal ranks (i.e., 

bituminous coal, subbituminous coal, 

lignite) or a blend of coal and coal 

refuse, you must not discharge into the 

atmosphere any gases from a new 

affected source that contain Hg in excess 

of the unit-specific Hg emissions limit 


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established according to paragraph 

(a)(5)(i) or (ii) of this section, as 

applicable to the affected unit. 

(i) If you operate a coal-fired electric 

utility steam generating unit that burns 

a blend of coals from different coal 

ranks or a blend of coal and coal refuse, 

you must not discharge into the 

atmosphere any gases from a new 

affected source that contain Hg in excess 

of the computed weighted Hg emissions 

limit based on the Btu, MWh, or MJ) 

contributed by each coal rank burned 

during the compliance period and its 

applicable Hg emissions limit in 

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

section as determined using Equation 1 

in this section. For each affected source, 

you must comply with the weighted Hg 

emissions limit calculated using 

Equation 1 in this section based on the 

total Hg emissions from the unit and the 

total Btu, MWh, or MJ contributed by all 

fuels burned during the compliance 

period. 

EL 1) b =

( ) =

=

∑

∑

EL HH

HH

Eq

i i

i

n

i

i

n

1

1

( .

Where: 

ELb = Total allowable Hg in lb/MWh that can 

be emitted to the atmosphere from any 

affected source being averaged according 

to this paragraph. 

ELi = Hg emissions limit for the subcategory 

i (coal rank) that applies to affected 

source, lb/MWh; 

HHi = For each affected source, the Btu, 

MWh, or MJ contributed by the 

corresponding subcategory i (coal rank) 

burned during the compliance period; 

and 

n = Number of subcategories (coal ranks) 

being averaged for an affected source. 

(ii) If you operate a coal-fired electric 

utility steam generating unit that burns 

a blend of coals from different coal 

ranks or a blend of coal and coal refuse 

together with one or more nonregulated, supplementary fuels, you 

must not discharge into the atmosphere 

any gases from a new affected source 

that contain Hg in excess of the 

computed weighted Hg emission limit 

based on the Btu, MWh, or MJ 

contributed by each coal rank burned 

during the compliance period and its 

applicable Hg emissions limit in 

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

section as determined using Equation 1 

in this section. For each affected source. 

You must comply with the weighted Hg 

emissions limit calculated using 

Equation 1 in this section based on the 

total Hg emissions from the unit 

contributed by both regulated and 

nonregulated fuels burned during the 

compliance period and the total Btu, 

MWh, or MJ contributed by both 

regulated and nonregulated fuels burned 

during the compliance period. 

(b) For each IGCC electric utility 

steam generating unit, on and after the 

date on which the initial performance 

test required to be conducted under 

§ 60.8 is completed, no owner or 

operator subject to the provisions of this 

subpart shall cause to be discharged into 

the atmosphere from any affected 

facility for which construction, 

modification, or reconstruction 

commenced after January 30, 2004, any 

gases that contain Hg emissions in 

excess of 20 × 10¥6 lb/MWh or 0.020 lb/ 

GWh on an output basis. The SI 

equivalent is 0.0025 ng/J. This Hg 

emissions limit is based on a 12-month 

rolling average basis using the 

procedures in § 60.50Da(h). 

§ 60.46Da [Reserved] 

§ 60.47Da Commercial demonstration 

permit. 

(a) An owner or operator of an 

affected facility proposing to 

demonstrate an emerging technology 

may apply to the Administrator for a 

commercial demonstration permit. The 

Administrator will issue a commercial 

demonstration permit in accordance 

with paragraph (e) of this section. 

Commercial demonstration permits may 

be issued only by the Administrator, 

and this authority will not be delegated. 

(b) An owner or operator of an 

affected facility that combusts solid 

solvent refined coal (SRC–I) and who is 

issued a commercial demonstration 

permit by the Administrator is not 

subject to the SO2 emission reduction 

requirements under § 60.43Da(c) but 

must, as a minimum, reduce SO2

emissions to 20 percent of the potential 

combustion concentration (80 percent 

reduction) for each 24-hour period of 

steam generator operation and to less 

than 520 ng/J (1.20 lb/MMBtu) heat 

input on a 30-day rolling average basis. 

(c) An owner or operator of a 

fluidized bed combustion electric utility 

steam generator (atmospheric or 

pressurized) who is issued a commercial 

demonstration permit by the 

Administrator is not subject to the SO2

emission reduction requirements under 

§ 60.43Da(a) but must, as a minimum, 

reduce SO2 emissions to 15 percent of 

the potential combustion concentration 

(85 percent reduction) on a 30-day 

rolling average basis and to less than 

520 ng/J (1.20 lb/MMBtu) heat input on 

a 30-day rolling average basis. 

(d) The owner or operator of an 

affected facility that combusts coalderived liquid fuel and who is issued a 

commercial demonstration permit by 

the Administrator is not subject to the 

applicable NOX emission limitation and 

percent reduction under § 60.44Da(a) 

but must, as a minimum, reduce 

emissions to less than 300 ng/J (0.70 lb/ 

MMBtu) heat input on a 30-day rolling 

average basis. 

(e) Commercial demonstration 

permits may not exceed the following 

equivalent MW electrical generation 

capacity for any one technology 

category, and the total equivalent MW 

electrical generation capacity for all 

commercial demonstration plants may 

not exceed 15,000 MW. 

Technology Pollutant 

Equivalent electrical capacity 

(MW electrical 

output) 

Solid solvent refined coal (SCR I) ........................................................................................................................... SO2 6,000–10,000 

Fluidized bed combustion (atmospheric) ................................................................................................................. SO2 400–3,000 

Fluidized bed combustion (pressurized) .................................................................................................................. SO2 400–1,200 

Coal liquification ....................................................................................................................................................... NOX 750–10,000 

Total allowable for all technologies .................................................................................................................. .................... 15,000 

§ 60.48Da Compliance provisions. 

(a) Compliance with the PM emission 

limitation under § 60.42Da(a)(1) 

constitutes compliance with the percent 

reduction requirements for PM under 

§ 60.42Da(a)(2) and (3). 

(b) Compliance with the NOX

emission limitation under 

§ 60.44Da(a)(1) constitutes compliance 

with the percent reduction requirements 

under § 60.44Da(a)(2). 


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32730 Federal Register / Vol. 72, No. 113 / Wednesday, June 13, 2007 / Rules and Regulations 

(c) The PM emission standards under 

§ 60.42Da, the NOX emission standards 

under § 60.44Da, and the Hg emission 

standards under § 60.45Da apply at all 

times except during periods of startup, 

shutdown, or malfunction. 

(d) During emergency conditions in 

the principal company, an affected 

facility with a malfunctioning flue gas 

desulfurization system may be operated 

if SO2 emissions are minimized by: 

(1) Operating all operable flue gas 

desulfurization system modules, and 

bringing back into operation any 

malfunctioned module as soon as 

repairs are completed, 

(2) Bypassing flue gases around only 

those flue gas desulfurization system 

modules that have been taken out of 

operation because they were incapable 

of any SO2 emission reduction or which 

would have suffered significant physical 

damage if they had remained in 

operation, and 

(3) Designing, constructing, and 

operating a spare flue gas 

desulfurization system module for an 

affected facility larger than 365 MW 

(1,250 MMBtu/hr) heat input 

(approximately 125 MW electrical 

output capacity). The Administrator 

may at his discretion require the owner 

or operator within 60 days of 

notification to demonstrate spare 

module capability. To demonstrate this 

capability, the owner or operator must 

demonstrate compliance with the 

appropriate requirements under 

paragraph under § 60.43Da(a), (b), (d), 

(e), and (h) for any period of operation 

lasting from 24 hours to 30 days when: 

(i) Any one flue gas desulfurization 

module is not operated, 

(ii) The affected facility is operating at 

the maximum heat input rate, 

(iii) The fuel fired during the 24-hour 

to 30-day period is representative of the 

type and average sulfur content of fuel 

used over a typical 30-day period, and 

(iv) The owner or operator has given 

the Administrator at least 30 days notice 

of the date and period of time over 

which the demonstration will be 

performed. 

(e) After the initial performance test 

required under § 60.8, compliance with 

the SO2 emission limitations and 

percentage reduction requirements 

under § 60.43Da and the NOX emission 

limitations under § 60.44Da is based on 

the average emission rate for 30 

successive boiler operating days. A 

separate performance test is completed 

at the end of each boiler operating day 

after the initial performance test, and a 

new 30 day average emission rate for 

both SO2 and NOX and a new percent 

reduction for SO2 are calculated to show 

compliance with the standards. 

(f) For the initial performance test 

required under § 60.8, compliance with 

the SO2 emission limitations and 

percent reduction requirements under 

§ 60.43Da and the NOX emission 

limitation under § 60.44Da is based on 

the average emission rates for SO2, NOX, 

and percent reduction for SO2 for the 

first 30 successive boiler operating days. 

The initial performance test is the only 

test in which at least 30 days prior 

notice is required unless otherwise 

specified by the Administrator. The 

initial performance test is to be 

scheduled so that the first boiler 

operating day of the 30 successive boiler 

operating days is completed within 60 

days after achieving the maximum 

production rate at which the affected 

facility will be operated, but not later 

than 180 days after initial startup of the 

facility. 

(g) The owner or operator of an 

affected facility subject to emission 

limitations in this subpart shall 

determine compliance as follows: 

(1) Compliance with applicable 30- 

day rolling average SO2 and NOX

emission limitations is determined by 

calculating the arithmetic average of all 

hourly emission rates for SO2 and NOX

for the 30 successive boiler operating 

days, except for data obtained during 

startup, shutdown, malfunction (NOX

only), or emergency conditions (SO2

only). 

(2) Compliance with applicable SO2

percentage reduction requirements is 

determined based on the average inlet 

and outlet SO2 emission rates for the 30 

successive boiler operating days. 

(3) Compliance with applicable daily 

average PM emission limitations is 

determined by calculating the 

arithmetic average of all hourly 

emission rates for PM each boiler 

operating day, except for data obtained 

during startup, shutdown, and 

malfunction. Averages are only 

calculated for boiler operating days that 

have valid data for at least 18 hours of 

unit operation during which the 

standard applies. Instead, the valid 

hourly emission rates are averaged with 

the next boiler operating day with 18 

hours or more of valid PM CEMS data 

to determine compliance. 

(h) If an owner or operator has not 

obtained the minimum quantity of 

emission data as required under 

§ 60.49Da of this subpart, compliance of 

the affected facility with the emission 

requirements under §§ 60.43Da and 

60.44Da of this subpart for the day on 

which the 30-day period ends may be 

determined by the Administrator by 

following the applicable procedures in 

section 7 of Method 19 of appendix A 

of this part. 

(i) Compliance provisions for sources 

subject to § 60.44Da(d)(1), (e)(1), 

(e)(2)(i), (e)(3)(i), or (f). The owner or 

operator of an affected facility subject to 

§ 60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), 

or (f) shall calculate NOX emissions as 

1.194 × 10¥7 lb/scf-ppm times the 

average hourly NOX output 

concentration in ppm (measured 

according to the provisions of 

§ 60.49Da(c)), times the average hourly 

flow rate (measured in scfh, according 

to the provisions of § 60.49Da(l) or 

§ 60.49Da(m)), divided by the average 

hourly gross energy output (measured 

according to the provisions of 

§ 60.49Da(k)). Alternatively, for oil-fired 

and gas-fired units, NOX emissions may 

be calculated by multiplying the hourly 

NOX emission rate in lb/MMBtu 

(measured by the CEMS required under 

§§ 60.49Da(c) and (d)), by the hourly 

heat input rate (measured according to 

the provisions of § 60.49Da(n)), and 

dividing the result by the average gross 

energy output (measured according to 

the provisions of § 60.49Da(k)). 

(j) Compliance provisions for duct 

burners subject to § 60.44Da(a)(1). To 

determine compliance with the 

emissions limits for NOX required by 

§ 60.44Da(a) for duct burners used in 

combined cycle systems, either of the 

procedures described in paragraph (j)(1) 

or (2) of this section may be used: 

(1) The owner or operator of an 

affected duct burner shall conduct the 

performance test required under § 60.8 

using the appropriate methods in 

appendix A of this part. Compliance 

with the emissions limits under 

§ 60.44Da(a)(1) is determined on the 

average of three (nominal 1-hour) runs 

for the initial and subsequent 

performance tests. During the 

performance test, one sampling site 

shall be located in the exhaust of the 

turbine prior to the duct burner. A 

second sampling site shall be located at 

the outlet from the heat recovery steam 

generating unit. Measurements shall be 

taken at both sampling sites during the 

performance test; or 

(2) The owner or operator of an 

affected duct burner may elect to 

determine compliance by using the 

continuous emission monitoring system 

(CEMS) specified under § 60.49Da for 

measuring NOX and oxygen (O2) (or 

carbon dioxide (CO2)) and meet the 

requirements of § 60.49Da. 

Alternatively, data from a NOX emission 

rate (i.e., NOX-diluent) CEMS certified 

according to the provisions of § 75.20(c) 

of this chapter and appendix A to part 

75 of this chapter, and meeting the 

quality assurance requirements of 

§ 75.21 of this chapter and appendix B 

to part 75 of this chapter, may be used, 


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with the following caveats. Data used to 

meet the requirements of § 60.51Da shall 

not include substitute data values 

derived from the missing data 

procedures in subpart D of part 75 of 

this chapter, nor shall the data have 

been bias adjusted according to the 

procedures of part 75 of this chapter. 

The sampling site shall be located at the 

outlet from the steam generating unit. 

The NOX emission rate at the outlet 

from the steam generating unit shall 

constitute the NOX emission rate from 

the duct burner of the combined cycle 

system. 

(k) Compliance provisions for duct 

burners subject to § 60.44Da(d)(1) or 

(e)(1). To determine compliance with 

the emission limitation for NOX

required by § 60.44Da(d)(1) or (e)(1) for 

duct burners used in combined cycle 

systems, either of the procedures 

described in paragraphs (k)(1) and (2) of 

this section may be used: 

(1) The owner or operator of an 

affected duct burner used in combined 

cycle systems shall determine 

compliance with the applicable NOX

emission limitation in § 60.44Da(d)(1) or 

(e)(1) as follows: 

(i) The emission rate (E) of NOX shall 

be computed using Equation 2 in this 

section: 

E

CQ CQ

O h Eq sg sg te te

sg

= ( ) × − × ( )

( ) ×

( . 2)

Where: 

E = Emission rate of NOX from the duct 

burner, ng/J (lb/MWh) gross output; 

Csg = Average hourly concentration of NOX

exiting the steam generating unit, ng/ 

dscm (lb/dscf); 

Cte = Average hourly concentration of NOX in 

the turbine exhaust upstream from duct 

burner, ng/dscm (lb/dscf); 

Qsg = Average hourly volumetric flow rate of 

exhaust gas from steam generating unit, 

dscm/hr (dscf/hr); 

Qte = Average hourly volumetric flow rate of 

exhaust gas from combustion turbine, 

dscm/hr (dscf/hr); 

Osg = Average hourly gross energy output 

from steam generating unit, J (MWh); and 

h = Average hourly fraction of the total heat 

input to the steam generating unit 

derived from the combustion of fuel in 

the affected duct burner. 

(ii) Method 7E of appendix A of this 

part shall be used to determine the NOX

concentrations (Csg and Cte). Method 2, 

2F or 2G of appendix A of this part, as 

appropriate, shall be used to determine 

the volumetric flow rates (Qsg and Qte) 

of the exhaust gases. The volumetric 

flow rate measurements shall be taken at 

the same time as the concentration 

measurements. 

(iii) The owner or operator shall 

develop, demonstrate, and provide 

information satisfactory to the 

Administrator to determine the average 

hourly gross energy output from the 

steam generating unit, and the average 

hourly percentage of the total heat input 

to the steam generating unit derived 

from the combustion of fuel in the 

affected duct burner. 

(iv) Compliance with the applicable 

NOX emission limitation in 

§ 60.44Da(d)(1) or (e)(1) is determined 

by the three-run average (nominal 1- 

hour runs) for the initial and subsequent 

performance tests. 

(2) The owner or operator of an 

affected duct burner used in a combined 

cycle system may elect to determine 

compliance with the applicable NOX

emission limitation in § 60.44Da(d)(1) or 

(e)(1) on a 30-day rolling average basis 

as indicated in paragraphs (k)(2)(i) 

through (iv) of this section. 

(i) The emission rate (E) of NOX shall 

be computed using Equation 3 in this 

section: 

E

C Q

O

sg sd

cc

= ( ) ×(Eq. 3)

Where: 

E = Emission rate of NOX from the duct 

burner, ng/J (lb/MWh) gross output; 

Csg = Average hourly concentration of NOX

exiting the steam generating unit, ng/ 

dscm (lb/dscf); 

Qsg = Average hourly volumetric flow rate of 

exhaust gas from steam generating unit, 

dscm/hr (dscf/hr); and 

Occ = Average hourly gross energy output 

from entire combined cycle unit, J 

(MWh). 

(ii) The CEMS specified under 

§ 60.49Da for measuring NOX and O2 (or 

CO2) shall be used to determine the 

average hourly NOX concentrations 

(Csg). The continuous flow monitoring 

system specified in § 60.49Da(l) or 

§ 60.49Da(m) shall be used to determine 

the volumetric flow rate (Qsg) of the 

exhaust gas. If the option to use the flow 

monitoring system in § 60.49Da(m) is 

selected, the flow rate data used to meet 

the requirements of § 60.51Da shall not 

include substitute data values derived 

from the missing data procedures in 

subpart D of part 75 of this chapter, nor 

shall the data have been bias adjusted 

according to the procedures of part 75 

of this chapter. The sampling site shall 

be located at the outlet from the steam 

generating unit. 

(iii) The continuous monitoring 

system specified under § 60.49Da(k) for 

measuring and determining gross energy 

output shall be used to determine the 

average hourly gross energy output from 

the entire combined cycle unit (Occ), 

which is the combined output from the 

combustion turbine and the steam 

generating unit. 

(iv) The owner or operator may, in 

lieu of installing, operating, and 

recording data from the continuous flow 

monitoring system specified in 

§ 60.49Da(l), determine the mass rate 

(lb/hr) of NOX emissions by installing, 

operating, and maintaining continuous 

fuel flowmeters following the 

appropriate measurements procedures 

specified in appendix D of part 75 of 

this chapter. If this compliance option is 

selected, the emission rate (E) of NOX

shall be computed using Equation 4 in 

this section: 

E

ER H

O

sg cc

cc

= ( ) ×(Eq. 4)

Where: 

E = Emission rate of NOX from the duct 

burner, ng/J (lb/MWh) gross output; 

ERsg = Average hourly emission rate of NOX

exiting the steam generating unit heat 

input calculated using appropriate F 

factor as described in Method 19 of 

appendix A of this part, ng/J (lb/ 

MMBtu); 

Hcc = Average hourly heat input rate of entire 

combined cycle unit, J/hr (MMBtu/hr); 

and 

Occ = Average hourly gross energy output 

from entire combined cycle unit, J 

(MWh). 

(3) When an affected duct burner 

steam generating unit utilizes a common 

steam turbine with one or more affected 

duct burner steam generating units, the 

owner or operator shall either: 

(i) Determine compliance with the 

applicable NOX emissions limits by 

measuring the emissions combined with 

the emissions from the other unit(s) 

utilizing the common steam turbine; or 

(ii) Develop, demonstrate, and 

provide information satisfactory to the 

Administrator on methods for 

apportioning the combined gross energy 

output from the steam turbine for each 

of the affected duct burners. The 

Administrator may approve such 

demonstrated substitute methods for 

apportioning the combined gross energy 

output measured at the steam turbine 

whenever the demonstration ensures 

accurate estimation of emissions 

regulated under this part. 

(l) Compliance provisions for sources 

subject to § 60.45Da. The owner or 

operator of an affected facility subject to 

§ 60.45Da (new sources constructed or 

reconstructed after January 30, 2004) 

shall calculate the Hg emission rate (lb/ 

MWh) for each calendar month of the 

year, using hourly Hg concentrations 

measured according to the provisions of 

§ 60.49Da(p) in conjunction with hourly 

stack gas volumetric flow rates 


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32732 Federal Register / Vol. 72, No. 113 / Wednesday, June 13, 2007 / Rules and Regulations 

measured according to the provisions of 

§ 60.49Da(l) or (m), and hourly gross 

electrical outputs, determined according 

to the provisions in § 60.49Da(k). 

Compliance with the applicable 

standard under § 60.45Da is determined 

on a 12-month rolling average basis. 

(m) Compliance provisions for sources 

subject to § 60.43Da(i)(1)(i), (i)(2)(i), 

(i)(3)(i), (j)(1)(i), (j)(2)(i), or (j)(3)(i). The 

owner or operator of an affected facility 

subject to § 60.43Da(i)(1)(i), (i)(2)(i), 

(i)(3)(i), (j)(1)(i), (j)(2)(i), or (j)(3)(i) shall 

calculate SO2 emissions as 1.660 × 10–7

lb/scf-ppm times the average hourly SO2

output concentration in ppm (measured 

according to the provisions of 

§ 60.49Da(b)), times the average hourly 

flow rate (measured according to the 

provisions of § 60.49Da(l) or 

§ 60.49Da(m)), divided by the average 

hourly gross energy output (measured 

according to the provisions of 

§ 60.49Da(k)). Alternatively, for oil-fired 

and gas-fired units, SO2 emissions may 

be calculated by multiplying the hourly 

SO2 emission rate (in lb/MMBtu), 

measured by the CEMS required under 

§ 60.49Da, by the hourly heat input rate 

(measured according to the provisions 

of § 60.49Da(n)), and dividing the result 

by the average gross energy output 

(measured according to the provisions 

of § 60.49Da(k)). 

(n) Compliance provisions for sources 

subject to § 60.42Da(c)(1). The owner or 

operator of an affected facility subject to 

§ 60.42Da(c)(1) shall calculate PM 

emissions by multiplying the average 

hourly PM output concentration, 

measured according to the provisions of 

§ 60.49Da(t), by the average hourly flow 

rate, measured according to the 

provisions of § 60.49Da(l), and divided 

by the average hourly gross energy 

output, measured according to the 

provisions of § 60.49Da(k). Compliance 

with the emission limit is determined 

by calculating the arithmetic average of 

the hourly emission rates computed for 

each boiler operating day. 

(o) Compliance provisions for sources 

subject to § 60.42Da(c)(2) or (d). Except 

as provided for in paragraph (p) of this 

section, the owner or operator of an 

affected facility for which construction, 

reconstruction, or modification 

commenced after February 28, 2005, 

shall demonstrate compliance with each 

applicable emission limit according to 

the requirements in paragraphs (o)(1) 

through (o)(5) of this section and use a 

COMS to demonstrate compliance with 

§ 60.42Da(b). 

(1) You must conduct a performance 

test to demonstrate initial compliance 

with the applicable PM emissions limit 

in 60.42Da(c)(2) or (d) by the applicable 

date specified in § 60.8(a). Thereafter, 

you must conduct each subsequent 

performance test within 12 calendar 

months of the date of the prior 

performance test. You must conduct 

each performance test according to the 

requirements in § 60.8 using the test 

methods and procedures in § 60.50Da. 

(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(c)(2) or (d) 

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. 

(i) Each COMS must meet 

Performance Specification 1 in 40 CFR 

part 60, appendix B. 

(ii) You must comply with the quality 

assurance requirements in paragraphs 

(o)(4)(ii)(A) through (E) of this section. 

(A) You must automatically (intrinsic 

to the opacity monitor) check the zero 

and upscale (span) calibration drifts at 

least once daily. For a particular COMS, 

the acceptable range of zero and upscale 

calibration materials is as defined in the 

applicable version of Performance 

Specification 1 in 40 CFR part 60, 

appendix B. 

(B) You must adjust the zero and span 

whenever the 24-hour zero drift or 24- 

hour span drift exceeds 4 percent 

opacity. The COMS must allow for the 

amount of excess zero and span drift 

measured at the 24-hour interval checks 

to be recorded and quantified. The 

optical surfaces exposed to the effluent 

gases must be cleaned prior to 

performing the zero and span drift 

adjustments, except for systems using 

automatic zero adjustments. For systems 

using automatic zero adjustments, the 

optical surfaces must be cleaned when 

the cumulative automatic zero 

compensation exceeds 4 percent 

opacity. 

(C) You must apply a method for 

producing a simulated zero opacity 

condition and an upscale (span) opacity 

condition using a certified neutral 

density filter or other related technique 

to produce a known obscuration of the 

light beam. All procedures applied must 

provide a system check of the analyzer 

internal optical surfaces and all 

electronic circuitry including the lamp 

and photodetector assembly. 

(D) Except during periods of system 

breakdowns, repairs, calibration checks, 

and zero and span adjustments, the 

COMS must be in continuous operation 

and must complete a minimum of one 

cycle of sampling and analyzing for 

each successive 10 second period and 

one cycle of data recording for each 

successive 6-minute period. 

(E) You must reduce all data from the 

COMS to 6-minute averages. Six-minute 

opacity averages must be calculated 

from 36 or more data points equally 

spaced over each 6-minute period. Data 

recorded during periods of system 

breakdowns, repairs, calibration checks, 

and zero and span adjustments must not 

be included in the data averages. An 

arithmetic or integrated average of all 

data may be used. 

(iii) During each performance test 

conducted according to paragraph (o)(1) 

of this section, you must establish an 

opacity baseline level. The value of the 

opacity baseline level is determined by 

averaging all of the 6-minute average 

opacity values (reported to the nearest 

0.1 percent opacity) from the COMS 

measurements recorded during each of 

the test run intervals conducted for the 

performance test, and then adding 2.5 

percent opacity to your calculated 

average opacity value for all of the test 

runs. If your calculated average opacity 

value for all of the test runs is less than 

5.0 percent, then the opacity baseline 

level is set at 5.0 percent. 

(iv) You must evaluate the preceding 

24-hour average opacity level measured 

by the COMS each boiler operating day 

excluding periods of affected source 

startup, shutdown, or malfunction. If 

the measured 24-hour average opacity 

emission level is greater than the 

baseline opacity level determined in 

paragraph (o)(2)(iii) of this section, you 

must initiate investigation of the 

relevant equipment and control systems 

within 24 hours of the first discovery of 

the high opacity incident and take the 

appropriate corrective action as soon as 

practicable to adjust control settings or 

repair equipment to reduce the 

measured 24-hour average opacity to a 

level below the baseline opacity level. 

(v) You must record the opacity 

measurements, calculations performed, 

and any corrective actions taken. The 

record of corrective action taken must 

include the date and time during which 

the measured 24-hour average opacity 

was greater than baseline opacity level, 

and the date, time, and description of 

the corrective action. 

(vi) If the measured 24-hour average 

opacity for your affected source remains 

at a level greater than the opacity 

baseline level after 7 days, then you 

must conduct a new PM performance 

test according to paragraph (o)(1) of this 

section and establish a new opacity 

baseline value according to paragraph 

(o)(2) of this section. This new 

performance test must be conducted 

within 60 days of the date that the 


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measured 24-hour average opacity was 

first determined to exceed the baseline 

opacity level unless a wavier is granted 

by the appropriate delegated permitting 

authority. 

(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(c)(2) or (d) 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(c)(2) or (d) 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 daily average liquid-to-gas 

flow rate for the wet scrubber must be 

maintained at 90 percent of average 

ratio measured during all test run 

intervals for the performance test 

conducted according to paragraph (o)(1) 

of this section. 

(ii) You must develop a site-specific 

monitoring plan that includes a 

description of the ESP predictive model 

used, the model input parameters, and 

the procedures and criteria for 

establishing monitoring parameter 

baseline levels indicative of compliance 

with the PM emissions limit. You must 

submit the site-specific monitoring plan 

for approval by the appropriate 

delegated permitting authority. For 

reference purposes in preparing the 

monitoring plan, see the OAQPS 

‘‘Compliance Assurance Monitoring 

(CAM) Protocol for an Electrostatic 

Precipitator (ESP) Controlling 

Particulate Matter (PM) Emissions from 

a Coal-Fired Boiler.’’ This document is 

available from the U.S. Environmental 

Protection Agency (U.S. EPA); Office of 

Air Quality Planning and 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 

Continuous Emission Monitoring . 

(iii) You must run the ESP predictive 

model using the applicable input data 

each boiler operating day and evaluate 

the model output for the preceding 

boiler operating day excluding periods 

of affected source startup, shutdown, or 

malfunction. If the values for one or 

more of the model parameters exceed 

the applicable baseline levels 

determined according to your approved 

site-specific monitoring plan, you must 

initiate investigation of the relevant 

equipment and control systems within 

24 hours of the first discovery of a 

model parameter deviation and, take the 

appropriate corrective action as soon as 

practicable to adjust control settings or 

repair equipment to return the model 

output to within the applicable baseline 

levels. 

(iv) You must record the ESP 

predictive model inputs and outputs 

and any corrective actions taken. The 

record of corrective action taken must 

include the date and time during which 

the model output values exceeded the 

applicable baseline levels, and the date, 

time, and description of the corrective 

action. 

(v) If after 7 consecutive days a model 

parameter continues to exceed the 

applicable baseline level, then you must 

conduct a new PM performance test 

according to paragraph (o)(1) of this 

section. This new performance test must 

be conducted within 60 days of the date 

that the model parameter was first 

determined to exceed its baseline level 

unless a wavier is granted by the 

appropriate delegated permitting 

authority. 

(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(c)(2) or 

(d) by using a bag leak detection system 

according to the requirements in 

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

section. 

(i) Each bag leak detection system 

must meet the specifications and 

requirements in paragraphs (o)(4)(i)(A) 

through (H) of this section. 

(A) The bag leak detection system 

must be certified by the manufacturer to 

be capable of detecting PM emissions at 

concentrations of 1 milligram per actual 

cubic meter (0.00044 grains per actual 

cubic foot) or less. 

(B) The bag leak detection system 

sensor must provide output of relative 

PM loadings. The owner or operator 

must continuously record the output 

from the bag leak detection system using 

electronic or other means (e.g., using a 

strip chart recorder or a data logger.) 

(C) The bag leak detection system 

must be equipped with an alarm system 

that will react when the system detects 

an increase in relative particulate 

loading over the alarm set point 

established according to paragraph 

(o)(4)(i)(D) of this section, and the alarm 

must be located such that it can be 

noticed by the appropriate plant 

personnel. 

(D) In the initial adjustment of the bag 

leak detection system, you must 

establish, at a minimum, the baseline 

output by adjusting the sensitivity 

(range) and the averaging period of the 

device, the alarm set points, and the 

alarm delay time. 

(E) Following initial adjustment, you 

must not adjust the averaging period, 

alarm set point, or alarm delay time 

without approval from the appropriate 

delegated permitting authority except as 

provided in paragraph (d)(1)(vi) of this 

section. 

(F) Once per quarter, you may adjust 

the sensitivity of the bag leak detection 

system to account for seasonal effects, 

including temperature and humidity, 

according to the procedures identified 

in the site-specific monitoring plan 

required by paragraph (o)(4)(ii) of this 

section. 

(G) You must install the bag leak 

detection sensor downstream of the 

fabric filter and upstream of any wet 

scrubber. 

(H) Where multiple detectors are 

required, the system’s instrumentation 

and alarm may be shared among 

detectors. 

(ii) You must develop and submit to 

the appropriate delegated permitting 

authority for approval a site-specific 

monitoring plan for each bag leak 

detection system. You must operate and 

maintain the bag leak detection system 

according to the site-specific monitoring 

plan at all times. Each monitoring plan 

must describe the items in paragraphs 

(o)(4)(ii)(A) through (F) of this section. 

(A) Installation of the bag leak 

detection system; 

(B) Initial and periodic adjustment of 

the bag leak detection system, including 

how the alarm set-point will be 

established; 

(C) Operation of the bag leak detection 

system, including quality assurance 

procedures; 

(D) How the bag leak detection system 

will be maintained, including a routine 

maintenance schedule and spare parts 

inventory list; 

(E) How the bag leak detection system 

output will be recorded and stored; and 

(F) Corrective action procedures as 

specified in paragraph (o)(4)(iii) of this 

section. In approving the site-specific 

monitoring plan, the appropriate 

delegated permitting authority may 

allow owners and operators more than 

3 hours to alleviate a specific condition 

that causes an alarm if the owner or 

operator identifies in the monitoring 

plan this specific condition as one that 

could lead to an alarm, adequately 

explains why it is not feasible to 


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alleviate this condition within 3 hours 

of the time the alarm occurs, and 

demonstrates that the requested time 

will ensure alleviation of this condition 

as expeditiously as practicable. 

(iii) For each bag leak detection 

system, you must initiate procedures to 

determine the cause of every alarm 

within 1 hour of the alarm. Except as 

provided in paragraph (o)(4)(ii)(F) of 

this section, you must alleviate the 

cause of the alarm within 3 hours of the 

alarm by taking whatever corrective 

action(s) are necessary. Corrective 

actions may include, but are not limited 

to the following: 

(A) Inspecting the fabric filter for air 

leaks, torn or broken bags or filter 

media, or any other condition that may 

cause an increase in particulate 

emissions; 

(B) Sealing off defective bags or filter 

media; 

(C) Replacing defective bags or filter 

media or otherwise repairing the control 

device; 

(D) Sealing off a defective fabric filter 

compartment; 

(E) Cleaning the bag leak detection 

system probe or otherwise repairing the 

bag leak detection system; or 

(F) Shutting down the process 

producing the particulate emissions. 

(iv) You must maintain records of the 

information specified in paragraphs 

(o)(4)(iv)(A) through (C) of this section 

for each bag leak detection system. 

(A) Records of the bag leak detection 

system output; 

(B) Records of bag leak detection 

system adjustments, including the date 

and time of the adjustment, the initial 

bag leak detection system settings, and 

the final bag leak detection system 

settings; and 

(C) The date and time of all bag leak 

detection system alarms, the time that 

procedures to determine the cause of the 

alarm were initiated, if procedures were 

initiated within 1 hour of the alarm, the 

cause of the alarm, an explanation of the 

actions taken, the date and time the 

cause of the alarm was alleviated, and 

if the alarm was alleviated within 3 

hours of the alarm. 

(v) If after any period of composed of 

30 boiler operating days during which 

the alarm rate exceeds 5 percent of the 

process operating time (excluding 

control device or process startup, 

shutdown, and malfunction), then you 

must conduct a new PM performance 

test according to paragraph (o)(1) of this 

section. This new performance test must 

be conducted within 60 days of the date 

that the alarm rate was first determined 

to exceed 5 percent limit unless a 

wavier is granted by the appropriate 

delegated permitting authority. 

(5) An owner or operator of a 

modified affected source electing to 

meet the emission limitations in 

§ .42Da(d) shall determine the percent 

reduction in PM by using the emission 

rate for PM determined by the 

performance test conducted according 

to the requirements in paragraph (o)(1) 

of this section and the ash content on a 

mass basis of the fuel burned during 

each performance test run as 

determined by analysis of the fuel as 

fired. 

(p) As an alternative to meeting the 

compliance provisions specified in 

paragraph (o) of this section, an owner 

or operator may elect to install, certify, 

maintain, and operate a CEMS 

measuring PM emissions discharged 

from the affected facility to the 

atmosphere and record the output of the 

system as specified in paragraphs (p)(1) 

through (p)(8) of this section. 

(1) The owner or operator shall 

submit a written notification to the 

Administrator of intent to demonstrate 

compliance with this subpart by using 

a CEMS measuring PM. This 

notification shall be sent at least 30 

calendar days before the initial startup 

of the monitor for compliance 

determination purposes. The owner or 

operator may discontinue operation of 

the monitor and instead return to 

demonstration of compliance with this 

subpart according to the requirements in 

paragraph (o) of this section by 

submitting written notification to the 

Administrator of such intent at least 30 

calendar days before shutdown of the 

monitor for compliance determination 

purposes. 

(2) Each CEMS shall be installed, 

certified, operated, and maintained 

according to the requirements in 

§ 60.49Da(v). 

(3) The initial performance evaluation 

shall be completed no later than 180 

days after the date of initial startup of 

the affected facility, as specified under 

§ 60.8 of subpart A of this part or within 

180 days of the date of notification to 

the Administrator required under 

paragraph (p)(1) of this section, 

whichever is later. 

(4) Compliance with the applicable 

emissions limit shall be determined 

based on the 24-hour daily (block) 

average of the hourly arithmetic average 

emissions concentrations using the 

continuous monitoring system outlet 

data. The 24-hour block arithmetic 

average emission concentration shall be 

calculated using EPA Reference Method 

19 of appendix A of this part, section 

4.1. 

(5) At a minimum, valid CEMS hourly 

averages shall be obtained for 75 percent 

of all operating hours on a 30-day 

rolling average basis. Beginning on 

January 1, 2012, valid CEMS hourly 

averages shall be obtained for 90 percent 

of all operating hours on a 30-day 

rolling average basis. 

(i) At least two data points per hour 

shall be used to calculate each 1-hour 

arithmetic average. 

(ii) [Reserved] 

(6) The 1-hour arithmetic averages 

required shall be expressed in ng/J, 

MMBtu/hr, or lb/MWh and shall be 

used to calculate the boiler operating 

day daily arithmetic average emission 

concentrations. The 1-hour arithmetic 

averages shall be calculated using the 

data points required under § 60.13(e)(2) 

of subpart A of this part. 

(7) All valid CEMS data shall be used 

in calculating average emission 

concentrations even if the minimum 

CEMS data requirements of paragraph 

(j)(5) of this section are not met. 

(8) When PM emissions data are not 

obtained because of CEMS breakdowns, 

repairs, calibration checks, and zero and 

span adjustments, emissions data shall 

be obtained by using other monitoring 

systems as approved by the 

Administrator or EPA Reference Method 

19 of appendix A of this part to provide, 

as necessary, valid emissions data for a 

minimum of 90 percent (only 75 percent 

is required prior to January 1, 2012) of 

all operating hours per 30-day rolling 

average. 

§ 60.49Da Emission monitoring. 

(a) Except as provided for in 

paragraphs (t) and (u) of this section, the 

owner or operator of an affected facility, 

shall install, calibrate, maintain, and 

operate a CEMS, and record the output 

of the system, for measuring the opacity 

of emissions discharged to the 

atmosphere. If opacity interference due 

to water droplets exists in the stack (for 

example, from the use of an FGD 

system), the opacity is monitored 

upstream of the interference (at the inlet 

to the FGD system). If opacity 

interference is experienced at all 

locations (both at the inlet and outlet of 

the SO2 control system), alternate 

parameters indicative of the PM control 

system’s performance and/or good 

combustion are monitored (subject to 

the approval of the Administrator). 

(b) The owner or operator of an 

affected facility shall install, calibrate, 

maintain, and operate a CEMS, and 

record the output of the system, for 

measuring SO2 emissions, except where 

natural gas is the only fuel combusted, 

as follows: 

(1) Sulfur dioxide emissions are 

monitored at both the inlet and outlet of 

the SO2 control device. 


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(2) For a facility that qualifies under 

the numerical limit provisions of 

§ 60.43Da(d), (i), (j), or (k) SO2 emissions 

are only monitored as discharged to the 

atmosphere. 

(3) An ‘‘as fired’’ fuel monitoring 

system (upstream of coal pulverizers) 

meeting the requirements of Method 19 

of appendix A of this part may be used 

to determine potential SO2 emissions in 

place of a continuous SO2 emission 

monitor at the inlet to the SO2 control 

device as required under paragraph 

(b)(1) of this section. 

(4) If the owner or operator has 

installed and certified a SO2 continuous 

emissions monitoring system (CEMS) 

according to the requirements of 

§ 75.20(c)(1) of this chapter and 

appendix A to part 75 of this chapter, 

and is continuing to meet the ongoing 

quality assurance requirements of 

§ 75.21 of this chapter and appendix B 

to part 75 of this chapter, that CEMS 

may be used to meet the requirements 

of this section, provided that: 

(i) A CO2 or O2 continuous monitoring 

system is installed, calibrated, 

maintained and operated at the same 

location, according to paragraph (d) of 

this section; and 

(ii) For sources subject to an SO2

emission limit in lb/MMBtu under 

§ 60.43Da: 

(A) When relative accuracy testing is 

conducted, SO2 concentration data and 

CO2 (or O2) data are collected 

simultaneously; and 

(B) In addition to meeting the 

applicable SO2 and CO2 (or O2) relative 

accuracy specifications in Figure 2 of 

appendix B to part 75 of this chapter, 

the relative accuracy (RA) standard in 

section 13.2 of Performance 

Specification 2 in appendix B to this 

part is met when the RA is calculated 

on a lb/MMBtu basis; and 

(iii) The reporting requirements of 

§ 60.51Da are met. The SO2 and CO2 (or 

O2) data reported to meet the 

requirements of § 60.51Da shall not 

include substitute data values derived 

from the missing data procedures in 

subpart D of part 75 of this chapter, nor 

shall the SO2 data have been bias 

adjusted according to the procedures of 

part 75 of this chapter. 

(c)(1) The owner or operator of an 

affected facility shall install, calibrate, 

maintain, and operate a CEMS, and 

record the output of the system, for 

measuring NOX emissions discharged to 

the atmosphere; or 

(2) If the owner or operator has 

installed a NOX emission rate CEMS to 

meet the requirements of part 75 of this 

chapter and is continuing to meet the 

ongoing requirements of part 75 of this 

chapter, that CEMS may be used to meet 

the requirements of this section, except 

that the owner or operator shall also 

meet the requirements of § 60.51Da. 

Data reported to meet the requirements 

of § 60.51Da shall not include data 

substituted using the missing data 

procedures in subpart D of part 75 of 

this chapter, nor shall the data have 

been bias adjusted according to the 

procedures of part 75 of this chapter. 

(d) The owner or operator of an 

affected facility shall install, calibrate, 

maintain, and operate a CEMS, and 

record the output of the system, for 

measuring the O2 or carbon dioxide 

(CO2) content of the flue gases at each 

location where SO2 or NOX emissions 

are monitored. For affected facilities 

subject to a lb/MMBtu SO2 emission 

limit under § 60.43Da, if the owner or 

operator has installed and certified a 

CO2 or O2 monitoring system according 

to § 75.20(c) of this chapter and 

Appendix A to part 75 of this chapter 

and the monitoring system continues to 

meet the applicable quality-assurance 

provisions of § 75.21 of this chapter and 

appendix B to part 75 of this chapter, 

that CEMS may be used together with 

the part 75 SO2 concentration 

monitoring system described in 

paragraph (b) of this section, to 

determine the SO2 emission rate in lb/ 

MMBtu. SO2 data used to meet the 

requirements of § 60.51Da shall not 

include substitute data values derived 

from the missing data procedures in 

subpart D of part 75 of this chapter, nor 

shall the data have been bias adjusted 

according to the procedures of part 75 

of this chapter. 

(e) The CEMS under paragraphs (b), 

(c), and (d) of this section are operated 

and data recorded during all periods of 

operation of the affected facility 

including periods of startup, shutdown, 

malfunction or emergency conditions, 

except for CEMS breakdowns, repairs, 

calibration checks, and zero and span 

adjustments. 

(f)(1) For units that began 

construction, reconstruction, or 

modification on or before February 28, 

2005, the owner or operator shall obtain 

emission data for at least 18 hours in at 

least 22 out of 30 successive boiler 

operating days. If this minimum data 

requirement cannot be met with CEMS, 

the owner or operator shall supplement 

emission data with other monitoring 

systems approved by the Administrator 

or the reference methods and 

procedures as described in paragraph 

(h) of this section. 

(2) For units that began construction, 

reconstruction, or modification after 

February 28, 2005, the owner or 

operator shall obtain emission data for 

at least 90 percent of all operating hours 

for each 30 successive boiler operating 

days. If this minimum data requirement 

cannot be met with a CEMS, the owner 

or operator shall supplement emission 

data with other monitoring systems 

approved by the Administrator or the 

reference methods and procedures as 

described in paragraph (h) of this 

section. 

(g) The 1-hour averages required 

under paragraph § 60.13(h) are 

expressed in ng/J (lb/MMBtu) heat input 

and used to calculate the average 

emission rates under § 60.48Da. The 1- 

hour averages are calculated using the 

data points required under § 60.13(h)(2). 

(h) When it becomes necessary to 

supplement CEMS data to meet the 

minimum data requirements in 

paragraph (f) of this section, the owner 

or operator shall use the reference 

methods and procedures as specified in 

this paragraph. Acceptable alternative 

methods and procedures are given in 

paragraph (j) of this section. 

(1) Method 6 of appendix A of this 

part shall be used to determine the SO2

concentration at the same location as 

the SO2 monitor. Samples shall be taken 

at 60-minute intervals. The sampling 

time and sample volume for each 

sample shall be at least 20 minutes and 

0.020 dscm (0.71 dscf). Each sample 

represents a 1-hour average. 

(2) Method 7 of appendix A of this 

part shall be used to determine the NOX

concentration at the same location as 

the NOX monitor. Samples shall be 

taken at 30-minute intervals. The 

arithmetic average of two consecutive 

samples represents a 1-hour average. 

(3) The emission rate correction 

factor, integrated bag sampling and 

analysis procedure of Method 3B of 

appendix A of this part shall be used to 

determine the O2 or CO2 concentration 

at the same location as the O2 or CO2

monitor. Samples shall be taken for at 

least 30 minutes in each hour. Each 

sample represents a 1-hour average. 

(4) The procedures in Method 19 of 

appendix A of this part shall be used to 

compute each 1-hour average 

concentration in ng/J (lb/MMBtu) heat 

input. 

(i) The owner or operator shall use 

methods and procedures in this 

paragraph to conduct monitoring system 

performance evaluations under 

§ 60.13(c) and calibration checks under 

§ 60.13(d). Acceptable alternative 

methods and procedures are given in 

paragraph (j) of this section. 

(1) Methods 3B, 6, and 7 of appendix 

A of this part shall be used to determine 

O2, SO2, and NOX concentrations, 

respectively. 

(2) SO2 or NOX (NO), as applicable, 

shall be used for preparing the 


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calibration gas mixtures (in N2, as 

applicable) under Performance 

Specification 2 of appendix B of this 

part. 

(3) For affected facilities burning only 

fossil fuel, the span value for a CEMS 

for measuring opacity is between 60 and 

80 percent. Span values for a CEMS 

measuring NOX shall be determined 

using one of the following procedures: 

(i) Except as provided under 

paragraph (i)(3)(ii) of this section, NOX

span values shall be determined as 

follows: 

Fossil fuel Span values for NOX

(ppm) 

Gas ........................... 500. 

Liquid ........................ 500. 

Solid .......................... 1,000. 

Combination .............. 500 (x + y) + 1,000z. 

Where: 

x = Fraction of total heat input derived from 

gaseous fossil fuel, 

y = Fraction of total heat input derived from 

liquid fossil fuel, and 

z = Fraction of total heat input derived from 

solid fossil fuel. 

(ii) As an alternative to meeting the 

requirements of paragraph (i)(3)(i) of 

this section, the owner or operator of an 

affected facility may elect to use the 

NOX span values determined according 

to section 2.1.2 in appendix A to part 75 

of this chapter. 

(4) All span values computed under 

paragraph (i)(3)(i) of this section for 

burning combinations of fossil fuels are 

rounded to the nearest 500 ppm. Span 

values computed under paragraph 

(i)(3)(ii) of this section shall be rounded 

off according to section 2.1.2 in 

appendix A to part 75 of this chapter. 

(5) For affected facilities burning 

fossil fuel, alone or in combination with 

non-fossil fuel and determining span 

values under paragraph (i)(3)(i) of this 

section, the span value of the SO2 CEMS 

at the inlet to the SO2 control device is 

125 percent of the maximum estimated 

hourly potential emissions of the fuel 

fired, and the outlet of the SO2 control 

device is 50 percent of maximum 

estimated hourly potential emissions of 

the fuel fired. For affected facilities 

determining span values under 

paragraph (i)(3)(ii) of this section, SO2

span values shall be determined 

according to section 2.1.1 in appendix A 

to part 75 of this chapter. 

(j) The owner or operator may use the 

following as alternatives to the reference 

methods and procedures specified in 

this section: 

(1) For Method 6 of appendix A of 

this part, Method 6A or 6B (whenever 

Methods 6 and 3 or 3B of appendix A 

of this part data are used) or 6C of 

appendix A of this part may be used. 

Each Method 6B of appendix A of this 

part sample obtained over 24 hours 

represents 24 1-hour averages. If Method 

6A or 6B of appendix A of this part is 

used under paragraph (i) of this section, 

the conditions under § 60.48Da(d)(1) 

apply; these conditions do not apply 

under paragraph (h) of this section. 

(2) For Method 7 of appendix A of 

this part, Method 7A, 7C, 7D, or 7E of 

appendix A of this part may be used. If 

Method 7C, 7D, or 7E of appendix A of 

this part is used, the sampling time for 

each run shall be 1 hour. 

(3) For Method 3 of appendix A of 

this part, Method 3A or 3B of appendix 

A of this part may be used if the 

sampling time is 1 hour. 

(4) For Method 3B of appendix A of 

this part, Method 3A of appendix A of 

this part may be used. 

(k) The procedures specified in 

paragraphs (k)(1) through (3) of this 

section shall be used to determine gross 

output for sources demonstrating 

compliance with the output-based 

standard under § 60.44Da(d)(1). 

(1) The owner or operator of an 

affected facility with electricity 

generation shall install, calibrate, 

maintain, and operate a wattmeter; 

measure gross electrical output in MWh 

on a continuous basis; and record the 

output of the monitor. 

(2) The owner or operator of an 

affected facility with process steam 

generation shall install, calibrate, 

maintain, and operate meters for steam 

flow, temperature, and pressure; 

measure gross process steam output in 

joules per hour (or Btu per hour) on a 

continuous basis; and record the output 

of the monitor. 

(3) For affected facilities generating 

process steam in combination with 

electrical generation, the gross energy 

output is determined from the gross 

electrical output measured in 

accordance with paragraph (k)(1) of this 

section plus 75 percent of the gross 

thermal output (measured relative to 

ISO conditions) of the process steam 

measured in accordance with paragraph 

(k)(2) of this section. 

(l) The owner or operator of an 

affected facility demonstrating 

compliance with an output-based 

standard under § 60.42Da, § 60.43Da, 

§ 60.44Da, or § 60.45Da shall install, 

certify, operate, and maintain a 

continuous flow monitoring system 

meeting the requirements of 

Performance Specification 6 of 

appendix B of this part and the CD 

assessment, RATA and reporting 

provisions of procedure 1 of appendix F 

of this part, and record the output of the 

system, for measuring the volumetric 

flow rate of exhaust gases discharged to 

the atmosphere; or 

(m) Alternatively, data from a 

continuous flow monitoring system 

certified according to the requirements 

of § 75.20(c) of this chapter and 

appendix A to part 75 of this chapter, 

and continuing to meet the applicable 

quality control and quality assurance 

requirements of § 75.21 of this chapter 

and appendix B to part 75 of this 

chapter, may be used. Flow rate data 

reported to meet the requirements of 

§ 60.51Da shall not include substitute 

data values derived from the missing 

data procedures in subpart D of part 75 

of this chapter, nor shall the data have 

been bias adjusted according to the 

procedures of part 75 of this chapter. 

(n) Gas-fired and oil-fired units. The 

owner or operator of an affected unit 

that qualifies as a gas-fired or oil-fired 

unit, as defined in 40 CFR 72.2, may 

use, as an alternative to the 

requirements specified in either 

paragraph (l) or (m) of this section, a 

fuel flow monitoring system certified 

and operated according to the 

requirements of appendix D of part 75 

of this chapter. 

(o) The owner or operator of a duct 

burner, as described in § 60.41Da, which 

is subject to the NOX standards of 

§ 60.44Da(a)(1), (d)(1), or (e)(1) is not 

required to install or operate a CEMS to 

measure NOX emissions; a wattmeter to 

measure gross electrical output; meters 

to measure steam flow, temperature, and 

pressure; and a continuous flow 

monitoring system to measure the flow 

of exhaust gases discharged to the 

atmosphere. 

(p) The owner or operator of an 

affected facility demonstrating 

compliance with an Hg limit in 

§ 60.45Da shall install and operate a 

CEMS to measure and record the 

concentration of Hg in the exhaust gases 

from each stack according to the 

requirements in paragraphs (p)(1) 

through (p)(3) of this section. 

Alternatively, for an affected facility 

that is also subject to the requirements 

of subpart I of part 75 of this chapter, 

the owner or operator may install, 

certify, maintain, operate and qualityassure the data from a Hg CEMS 

according to § 75.10 of this chapter and 

appendices A and B to part 75 of this 

chapter, in lieu of following the 

procedures in paragraphs (p)(1) through 

(p)(3) of this section. 

(1) The owner or operator must 

install, operate, and maintain each 

CEMS according to Performance 

Specification 12A in appendix B to this 

part. 

(2) The owner or operator must 

conduct a performance evaluation of 


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each CEMS according to the 

requirements of § 60.13 and 

Performance Specification 12A in 

appendix B to this part. 

(3) The owner or operator must 

operate each CEMS according to the 

requirements in paragraphs (p)(3)(i) 

through (iv) of this section. 

(i) As specified in § 60.13(e)(2), each 

CEMS must complete a minimum of one 

cycle of operation (sampling, analyzing, 

and data recording) for each successive 

15-minute period. 

(ii) The owner or operator must 

reduce CEMS data as specified in 

§ 60.13(h). 

(iii) The owner or operator shall use 

all valid data points collected during the 

hour to calculate the hourly average Hg 

concentration. 

(iv) The owner or operator must 

record the results of each required 

certification and quality assurance test 

of the CEMS. 

(4) Mercury CEMS data collection 

must conform to paragraphs (p)(4)(i) 

through (iv) of this section. 

(i) For each calendar month in which 

the affected unit operates, valid hourly 

Hg concentration data, stack gas 

volumetric flow rate data, moisture data 

(if required), and electrical output data 

(i.e., valid data for all of these 

parameters) shall be obtained for at least 

75 percent of the unit operating hours 

in the month. 

(ii) Data reported to meet the 

requirements of this subpart shall not 

include hours of unit startup, shutdown, 

or malfunction. In addition, for an 

affected facility that is also subject to 

subpart I of part 75 of this chapter, data 

reported to meet the requirements of 

this subpart shall not include data 

substituted using the missing data 

procedures in subpart D of part 75 of 

this chapter, nor shall the data have 

been bias adjusted according to the 

procedures of part 75 of this chapter. 

(iii) If valid data are obtained for less 

than 75 percent of the unit operating 

hours in a month, you must discard the 

data collected in that month and replace 

the data with the mean of the individual 

monthly emission rate values 

determined in the last 12 months. In the 

12-month rolling average calculation, 

this substitute Hg emission rate shall be 

weighted according to the number of 

unit operating hours in the month for 

which the data capture requirement of 

§ 60.49Da(p)(4)(i) was not met. 

(iv) Notwithstanding the requirements 

of paragraph (p)(4)(iii) of this section, if 

valid data are obtained for less than 75 

percent of the unit operating hours in 

another month in that same 12-month 

rolling average cycle, discard the data 

collected in that month and replace the 

data with the highest individual 

monthly emission rate determined in 

the last 12 months. In the 12-month 

rolling average calculation, this 

substitute Hg emission rate shall be 

weighted according to the number of 

unit operating hours in the month for 

which the data capture requirement of 

§ 60.49Da(p)(4)(i) was not met. 

(q) As an alternative to the CEMS 

required in paragraph (p) of this section, 

the owner or operator may use a sorbent 

trap monitoring system (as defined in 

§ 72.2 of this chapter) to monitor Hg 

concentration, according to the 

procedures described in § 75.15 of this 

chapter and appendix K to part 75 of 

this chapter. 

(r) For Hg CEMS that measure Hg 

concentration on a dry basis or for 

sorbent trap monitoring systems, the 

emissions data must be corrected for the 

stack gas moisture content. A certified 

continuous moisture monitoring system 

that meets the requirements of § 75.11(b) 

of this chapter is acceptable for this 

purpose. Alternatively, the appropriate 

default moisture value, as specified in 

§ 75.11(b) or § 75.12(b) of this chapter, 

may be used. 

(s) The owner or operator shall 

prepare and submit to the Administrator 

for approval a unit-specific monitoring 

plan for each monitoring system, at least 

45 days before commencing certification 

testing of the monitoring systems. The 

owner or operator shall comply with the 

requirements in your plan. The plan 

must address the requirements in 

paragraphs (s)(1) through (6) of this 

section. 

(1) Installation of the CEMS sampling 

probe or other interface at a 

measurement location relative to each 

affected process unit such that the 

measurement is representative of the 

exhaust emissions (e.g., on or 

downstream of the last control device); 

(2) Performance and equipment 

specifications for the sample interface, 

the pollutant concentration or 

parametric signal analyzer, and the data 

collection and reduction systems; 

(3) Performance evaluation 

procedures and acceptance criteria (e.g., 

calibrations, relative accuracy test 

audits (RATA), etc.); 

(4) Ongoing operation and 

maintenance procedures in accordance 

with the general requirements of 

§ 60.13(d) or part 75 of this chapter (as 

applicable); 

(5) Ongoing data quality assurance 

procedures in accordance with the 

general requirements of § 60.13 or part 

75 of this chapter (as applicable); and 

(6) Ongoing recordkeeping and 

reporting procedures in accordance with 

the requirements of this subpart. 

(t) The owner or operator of an 

affected facility demonstrating 

compliance with the output-based 

emissions limitation under 

§ 60.42Da(c)(1) shall install, certify, 

operate, and maintain a CEMS for 

measuring PM emissions according to 

the requirements of paragraph (v) of this 

section. An owner or operator of an 

affected source demonstrating 

compliance with the input-based 

emission limitation under 

§ 60.42Da(c)(2) may install, certify, 

operate, and maintain a CEMS for 

measuring PM emissions according to 

the requirements of paragraph (v) of this 

section. 

(u) An owner or operator of an 

affected source that meets the 

conditions in either paragraph (u)(1), (2) 

or (3) of this section is exempted from 

the continuous opacity monitoring 

system requirements in paragraph (a) of 

this section and the monitoring 

requirements in § 60.48Da(o). 

(1) A CEMS for measuring PM 

emissions is used to demonstrate 

continuous compliance on a boiler 

operating day average with the 

emissions limitations under 

§ 60.42Da(a)(1) or § 60.42Da(c)(2) and is 

installed, certified, operated, and 

maintained on the affected source 

according to the requirements of 

paragraph (v) of this section; or 

(2) The affected source burns only 

gaseous fuels and does not use a postcombustion technology to reduce 

emissions of SO2 or PM; or 

(3) The affected source does not use 

post-combustion technology (except a 

wet scrubber) for reducing PM, SO2, or 

carbon monoxide (CO) emissions, burns 

only natural gas, gaseous fuels, or fuel 

oils that contain less than or equal to 

0.30 weight percent sulfur, and is 

operated such that emissions of CO to 

the atmosphere from the affected source 

are maintained at levels less than or 

equal to 1.4 lb/MWh on a boiler 

operating day average basis. Owners and 

operators of affected sources electing to 

comply with this paragraph must 

demonstrate compliance according to 

the procedures specified in paragraphs 

(u)(3)(i) through (iv) of this section. 

(i) You must monitor CO emissions 

using a CEMS according to the 

procedures specified in paragraphs 

(u)(3)(i)(A) through (D) of this section. 

(A) The CO CEMS must be installed, 

certified, maintained, and operated 

according to the provisions in 

§ 60.58b(i)(3) of subpart Eb of this part. 

(B) Each 1-hour CO emissions average 

is calculated using the data points 

generated by the CO CEMS expressed in 

parts per million by volume corrected to 

3 percent oxygen (dry basis). 


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(C) At a minimum, valid 1-hour CO 

emissions averages must be obtained for 

at least 90 percent of the operating 

hours on a 30-day rolling average basis. 

At least two data points per hour must 

be used to calculate each 1-hour 

average. 

(D) Quarterly accuracy determinations 

and daily calibration drift tests for the 

CO CEMS must be performed in 

accordance with procedure 1 in 

appendix F of this part. 

(ii) You must calculate the 1-hour 

average CO emissions levels for each 

boiler operating day by multiplying the 

average hourly CO output concentration 

measured by the CO CEMS times the 

corresponding average hourly flue gas 

flow rate and divided by the 

corresponding average hourly useful 

energy output from the affected source. 

The 24-hour average CO emission level 

is determined by calculating the 

arithmetic average of the hourly CO 

emission levels computed for each 

boiler operating day. 

(iii) You must evaluate the preceding 

24-hour average CO emission level each 

boiler operating day excluding periods 

of affected source startup, shutdown, or 

malfunction. If the 24-hour average CO 

emission level is greater than 1.4 lb/ 

MWh, you must initiate investigation of 

the relevant equipment and control 

systems within 24 hours of the first 

discovery of the high emission incident 

and, take the appropriate corrective 

action as soon as practicable to adjust 

control settings or repair equipment to 

reduce the 24-hour average CO emission 

level to 1.4 lb/MWh or less. 

(iv) You must record the CO 

measurements and calculations 

performed according to paragraph (u)(3) 

of this section and any corrective 

actions taken. The record of corrective 

action taken must include the date and 

time during which the 24-hour average 

CO emission level was greater than 1.4 

lb/MWh, and the date, time, and 

description of the corrective action. 

(v) The owner or operator of an 

affected facility using a CEMS 

measuring PM emissions to meet 

requirements of this subpart shall 

install, certify, operate, and maintain 

the CEMS as specified in paragraphs 

(v)(1) through (v)(3). 

(1) The owner or operator shall 

conduct a performance evaluation of the 

CEMS according to the applicable 

requirements of § 60.13, Performance 

Specification 11 in appendix B of this 

part, and procedure 2 in appendix F of 

this part. 

(2) During each relative accuracy test 

run of the CEMS required by 

Performance Specification 11 in 

appendix B of this part, PM and O2 (or 

CO2) data shall be collected 

concurrently (or within a 30-to 60- 

minute period) by both the CEMS and 

conducting performance tests using the 

following test methods. 

(i) For PM, EPA Reference Method 5, 

5B, or 17 of appendix A of this part 

shall be used. 

(ii) For O2 (or CO2), EPA Reference 

Method 3, 3A, or 3B of appendix A of 

this part, as applicable shall be used. 

(3) Quarterly accuracy determinations 

and daily calibration drift tests shall be 

performed in accordance with 

procedure 2 in appendix F of this part. 

Relative Response Audit’s must be 

performed annually and Response 

Correlation Audits must be performed 

every 3 years. 

(w)(1) Except as provided for under 

paragraphs (w)(2), (w)(3), and (w)(4) of 

this section, the SO2, NOX, CO2, and O2

CEMS required under paragraphs (b) 

through (d) of this section shall be 

installed, certified, and operated in 

accordance with the applicable 

procedures in Performance 

Specification 2 or 3 in appendix B to 

this part or according to the procedures 

in appendices A and B to part 75 of this 

chapter. Daily calibration drift 

assessments and quarterly accuracy 

determinations shall be done in 

accordance with Procedure 1 in 

appendix F to this part, and a data 

assessment report (DAR), prepared 

according to section 7 of Procedure 1 in 

appendix F to this part, shall be 

submitted with each compliance report 

required under § 60.51Da., the owner or 

operator may elect to implement the 

following alternative data accuracy 

assessment procedures: 

(2) As an alternative to meeting the 

requirements of paragraph (w)(1) of this 

section, an owner or operator may elect 

to may elect to implement the following 

alternative data accuracy assessment 

procedures. For all required CO2 and O2

CEMS and for SO2 and NOX CEMS with 

span values greater than 100 ppm, the 

daily calibration error test and 

calibration adjustment procedures 

described in sections 2.1.1 and 2.1.3 of 

appendix B to part 75 of this chapter 

may be followed instead of the CD 

assessment procedures in Procedure 1, 

section 4.1 of appendix F of this part. If 

this option is selected, the data 

validation and out-of-control provisions 

in sections 2.1.4 and 2.1.5 of appendix 

B to part 75 of this chapter shall be 

followed instead of the excessive CD 

and out-of-control criteria in Procedure 

1, section 4.3 of appendix F to this part. 

For the purposes of data validation 

under this subpart, the excessive CD 

and out-of-control criteria in Procedure 

1, section 4.3 of appendix F to this part 

shall apply to SO2 and NOX span values 

less than 100 ppm; 

(3) As an alternative to meeting the 

requirements of paragraph (w)(1) of this 

section, an owner or operator may elect 

to may elect to implement the following 

alternative data accuracy assessment 

procedures. For all required CO2 and O2

CEMS and for SO2 and NOX CEMS with 

span values greater than 30 ppm, 

quarterly linearity checks may be 

performed in accordance with section 

2.2.1 of appendix B to part 75 of this 

chapter, instead of performing the 

cylinder gas audits (CGAs) described in 

Procedure 1, section 5.1.2 of appendix 

F to this part. If this option is selected: 

The frequency of the linearity checks 

shall be as specified in section 2.2.1 of 

appendix B to part 75 of this chapter; 

the applicable linearity specifications in 

section 3.2 of appendix A to part 75 of 

this chapter shall be met; the data 

validation and out-of-control criteria in 

section 2.2.3 of appendix B to part 75 

of this chapter shall be followed instead 

of the excessive audit inaccuracy and 

out-of-control criteria in Procedure 1, 

section 5.2 of appendix F to this part; 

and the grace period provisions in 

section 2.2.4 of appendix B to part 75 

of this chapter shall apply. For the 

purposes of data validation under this 

subpart, the cylinder gas audits 

described in Procedure 1, section 5.1.2 

of appendix F to this part shall be 

performed for SO2 and NOX span values 

less than or equal to 30 ppm; 

(4) As an alternative to meeting the 

requirements of paragraph (w)(1) of this 

section, an owner or operator may elect 

to may elect to implement the following 

alternative data accuracy assessment 

procedures. For SO2, CO2, and O2 CEMS 

and for NOX CEMS, RATAs may be 

performed in accordance with section 

2.3 of appendix B to part 75 of this 

chapter instead of following the 

procedures described in Procedure 1, 

section 5.1.1 of appendix F to this part. 

If this option is selected: The frequency 

of each RATA shall be as specified in 

section 2.3.1 of appendix B to part 75 

of this chapter; the applicable relative 

accuracy specifications shown in Figure 

2 in appendix B to part 75 of this 

chapter shall be met; the data validation 

and out-of-control criteria in section 

2.3.2 of appendix B to part 75 of this 

chapter shall be followed instead of the 

excessive audit inaccuracy and out-ofcontrol criteria in Procedure 1, section 

5.2 of appendix F to this part; and the 

grace period provisions in section 2.3.3 

of appendix B to part 75 of this chapter 

shall apply. For the purposes of data 

validation under this subpart, the 

relative accuracy specification in 

section 13.2 of Performance 


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Specification 2 in appendix B to this 

part shall be met on a lb/MMBtu basis 

for SO2 (regardless of the SO2 emission 

level during the RATA), and for NOX

when the average NOX emission rate 

measured by the reference method 

during the RATA is less than 0.100 lb/ 

MMBtu; 

(5) If the owner or operator elects to 

implement the alternative data 

assessment procedures described in 

paragraphs (w)(2) through (w)(4) of this 

section, each data assessment report 

shall include a summary of the results 

of all of the RATAs, linearity checks, 

CGAs, and calibration error or drift 

assessments required by paragraphs 

(w)(2) through (w)(4) of this section. 

§ 60.50Da Compliance determination 

procedures and methods. 

(a) In conducting the performance 

tests required in § 60.8, the owner or 

operator shall use as reference methods 

and procedures the methods in 

appendix A of this part or the methods 

and procedures as specified in this 

section, except as provided in § 60.8(b). 

Section 60.8(f) does not apply to this 

section for SO2 and NOX. Acceptable 

alternative methods are given in 

paragraph (e) of this section. 

(b) The owner or operator shall 

determine compliance with the PM 

standards in § 60.42Da as follows: 

(1) The dry basis F factor (O2) 

procedures in Method 19 of appendix A 

of this part shall be used to compute the 

emission rate of PM. 

(2) For the particular matter 

concentration, Method 5 of appendix A 

of this part shall be used at affected 

facilities without wet FGD systems and 

Method 5B of appendix A of this part 

shall be used after wet FGD systems. 

(i) The sampling time and sample 

volume for each run shall be at least 120 

minutes and 1.70 dscm (60 dscf). The 

probe and filter holder heating system 

in the sampling train may be set to 

provide an average gas temperature of 

no greater than 160±14 °C (320±25 °F). 

(ii) For each particulate run, the 

emission rate correction factor, 

integrated or grab sampling and analysis 

procedures of Method 3B of appendix A 

of this part shall be used to determine 

the O2 concentration. The O2 sample 

shall be obtained simultaneously with, 

and at the same traverse points as, the 

particulate run. If the particulate run 

has more than 12 traverse points, the O2

traverse points may be reduced to 12 

provided that Method 1 of appendix A 

of this part is used to locate the 12 O2

traverse points. If the grab sampling 

procedure is used, the O2 concentration 

for the run shall be the arithmetic mean 

of the sample O2 concentrations at all 

traverse points. 

(3) Method 9 of appendix A of this 

part and the procedures in § 60.11 shall 

be used to determine opacity. 

(c) The owner or operator shall 

determine compliance with the SO2

standards in § 60.43Da as follows: 

(1) The percent of potential SO2

emissions (%Ps) to the atmosphere shall 

be computed using the following 

equation: 

%

% %

P

R R

s

f g

= ( ) 100 100 − ( ) −

100

Where: 

%Ps = Percent of potential SO2 emissions, 

percent; 

%Rf = Percent reduction from fuel 

pretreatment, percent; and 

%Rg = Percent reduction by SO2 control 

system, percent. 

(2) The procedures in Method 19 of 

appendix A of this part may be used to 

determine percent reduction (%Rf) of 

sulfur by such processes as fuel 

pretreatment (physical coal cleaning, 

hydrodesulfurization of fuel oil, etc.), 

coal pulverizers, and bottom and fly ash 

interactions. This determination is 

optional. 

(3) The procedures in Method 19 of 

appendix A of this part shall be used to 

determine the percent SO2 reduction 

(%Rg) of any SO2 control system. 

Alternatively, a combination of an ‘‘as 

fired’’ fuel monitor and emission rates 

measured after the control system, 

following the procedures in Method 19 

of appendix A of this part, may be used 

if the percent reduction is calculated 

using the average emission rate from the 

SO2 control device and the average SO2

input rate from the ‘‘as fired’’ fuel 

analysis for 30 successive boiler 

operating days. 

(4) The appropriate procedures in 

Method 19 of appendix A of this part 

shall be used to determine the emission 

rate. 

(5) The CEMS in § 60.49Da(b) and (d) 

shall be used to determine the 

concentrations of SO2 and CO2 or O2. 

(d) The owner or operator shall 

determine compliance with the NOX

standard in § 60.44Da as follows: 

(1) The appropriate procedures in 

Method 19 of appendix A of this part 

shall be used to determine the emission 

rate of NOX. 

(2) The continuous monitoring system 

in § 60.49Da(c) and (d) shall be used to 

determine the concentrations of NOX

and CO2 or O2. 

(e) The owner or operator may use the 

following as alternatives to the reference 

methods and procedures specified in 

this section: 

(1) For Method 5 or 5B of appendix 

A of this part, Method 17 of appendix 

A of this part may be used at facilities 

with or without wet FGD systems if the 

stack temperature at the sampling 

location does not exceed an average 

temperature of 160 °C (320 °F). The 

procedures of §§ 2.1 and 2.3 of Method 

5B of appendix A of this part may be 

used in Method 17 of appendix A of this 

part only if it is used after wet FGD 

systems. Method 17 of appendix A of 

this part shall not be used after wet FGD 

systems if the effluent is saturated or 

laden with water droplets. 

(2) The Fc factor (CO2) procedures in 

Method 19 of appendix A of this part 

may be used to compute the emission 

rate of PM under the stipulations of 

§ 60.46(d)(1). The CO2 shall be 

determined in the same manner as the 

O2 concentration. 

(f) Electric utility combined cycle gas 

turbines are performance tested for PM, 

SO2, and NOX using the procedures of 

Method 19 of appendix A of this part. 

The SO2 and NOX emission rates from 

the gas turbine used in Method 19 of 

appendix A of this part calculations 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. 

(g) For the purposes of determining 

compliance with the emission limits in 

§ 60.45Da, the owner or operator of an 

electric utility steam generating unit 

which is also a cogeneration unit shall 

use the procedures in paragraphs (g)(1) 

and (2) of this section to calculate 

emission rates based on electrical 

output to the grid plus 75 percent of the 

equivalent electrical energy (measured 

relative to ISO conditions) in the unit’s 

process stream. 

(1) All conversions from Btu/hr unit 

input to MW unit output must use 

equivalents found in 40 CFR 60.40(a)(1) 

for electric utilities (i.e., 250 MMBtu/hr 

input to an electric utility steam 

generating unit is equivalent to 73 MW 

input to the electric utility steam 

generating unit); 73 MW input to the 

electric utility steam generating unit is 

equivalent to 25 MW output from the 

boiler electric utility steam generating 

unit; therefore, 250 MMBtu input to the 

electric utility steam generating unit is 

equivalent to 25 MW output from the 

electric utility steam generating unit). 

(2) Use the Equation 5 in this section 

to determine the cogeneration Hg 

emission rate over a specific compliance 

period. 


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ER M

V V cogen

grid process

=

( ) + × 0 75 . (Eq. 5)

Where: 

ERcogen = Cogeneration Hg emission rate over 

a compliance period in lb/MWh; 

E = Mass of Hg emitted from the stack over 

the same compliance period (lb); 

Vgrid = Amount of energy sent to the grid over 

the same compliance period (MWh); and 

Vprocess = Amount of energy converted to 

steam for process use over the same 

compliance period (MWh). 

(h) The owner or operator shall 

determine compliance with the Hg limit 

in § 60.45Da according to the 

procedures in paragraphs (h)(1) through 

(3) of this section. 

(1) The initial performance test shall 

be commenced by the applicable date 

specified in § 60.8(a). The required 

CEMS must be certified prior to 

commencing the test. The performance 

test consists of collecting hourly Hg 

emission data (lb/MWh) with the CEMS 

for 12 successive months of unit 

operation (excluding hours of unit 

startup, shutdown and malfunction). 

The average Hg emission rate is 

calculated for each month, and then the 

weighted, 12-month average Hg 

emission rate is calculated according to 

paragraph (h)(2) or (h)(3) of this section, 

as applicable. If, for any month in the 

initial performance test, the minimum 

data capture requirement in 

§ 60.49Da(p)(4)(i) is not met, the owner 

or operator shall report a substitute Hg 

emission rate for that month, as follows. 

For the first such month, the substitute 

monthly Hg emission rate shall be the 

arithmetic average of all valid hourly Hg 

emission rates recorded to date. For any 

subsequent month(s) with insufficient 

data capture, the substitute monthly Hg 

emission rate shall be the highest valid 

hourly Hg emission rate recorded to 

date. When the 12-month average Hg 

emission rate for the initial performance 

test is calculated, for each month in 

which there was insufficient data 

capture, the substitute monthly Hg 

emission rate shall be weighted 

according to the number of unit 

operating hours in that month. 

Following the initial performance test, 

the owner or operator shall demonstrate 

compliance by calculating the weighted 

average of all monthly Hg emission rates 

(in lb/MWh) for each 12 successive 

calendar months, excluding data 

obtained during startup, shutdown, or 

malfunction. 

(2) If a CEMS is used to demonstrate 

compliance, follow the procedures in 

paragraphs (h)(2)(i) through (iii) of this 

section to determine the 12-month 

rolling average. 

(i) Calculate the total mass of Hg 

emissions over a month (M), in lb, using 

either Equation 6 in paragraph 

(h)(2)(i)(A) of this section or Equation 7 

in paragraph (h)(2)(i)(B) of this section, 

in conjunction with Equation 8 in 

paragraph (h)(2)(i)(C) of this section. 

(A) If the Hg CEMS measures Hg 

concentration on a wet basis, use 

Equation 6 below to calculate the Hg 

mass emissions for each valid hour: 

E KC h h = Q t (Eq. 6) h h

Where: 

Eh = Hg mass emissions for the hour, (lb); 

K = Units conversion constant, 6.24 × 10¥11

lb-scm/μgm-scf; 

Ch = Hourly Hg concentration, wet basis, 

(μgm/scm); 

Qh = Hourly stack gas volumetric flow rate, 

(scfh); and 

th = Unit operating time, i.e., the fraction of 

the hour for which the unit operated. For 

example, th = 0.50 for a half-hour of unit 

operation and 1.00 for a full hour of 

operation. 

(B) If the Hg CEMS measures Hg 

concentration on a dry basis, use 

Equation 7 below to calculate the Hg 

mass emissions for each valid hour: 

E KC B h h ws = − Q t 1 (Eq. 7) h h ( )

Where: 

Eh = Hg mass emissions for the hour, (lb); 

K = Units conversion constant, 6.24 × 10¥11

lb-scm/μgm-scf; 

Ch = Hourly Hg concentration, dry basis, 

(μgm/dscm); 

Qh = Hourly stack gas volumetric flow rate, 

(scfh); 

th = Unit operating time, i.e., the fraction of 

the hour for which the unit operated; 

and 

Bws = Stack gas moisture content, expressed 

as a decimal fraction (e.g., for 8 percent 

H2O, Bws = 0.08). 

(C) Use Equation 8, below, to 

calculate M, the total mass of Hg 

emitted for the month, by summing the 

hourly masses derived from Equation 6 

or 7 (as applicable): 

M Eh

h

n

= =

∑1

(Eq. 8)

M = Total Hg mass emissions for the month, 

(lb); 

Eh = Hg mass emissions for hour ‘‘h’’, from 

Equation 6 or 7 of this section, (lb); and 

n = Number of unit operating hours in the 

month with valid CE and electrical 

output data, excluding hours of unit 

startup, shutdown and malfunction. 

(ii) Calculate the monthly Hg 

emission rate on an output basis (lb/ 

MWh) using Equation 9, below. For a 

cogeneration unit, use Equation 5 in 

paragraph (g) of this section instead. 

ER M

P = (Eq. 9)

Where: 

ER = Monthly Hg emission rate, (lb/MWh); 

M = Total mass of Hg emissions for the 

month, from Equation 8, above, (lb); and 

P = Total electrical output for the month, 

for the hours used to calculate M, (MWh). 

(iii) Until 12 monthly Hg emission 

rates have been accumulated, calculate 

and report only the monthly averages. 

Then, for each subsequent calendar 

month, use Equation 10 below to 

calculate the 12-month rolling average 

as a weighted average of the Hg 

emission rate for the current month and 

the Hg emission rates for the previous 

11 months, with one exception. 

Calendar months in which the unit does 

not operate (zero unit operating hours) 

shall not be included in the 12-month 

rolling average. 

E

ER n

n

avg

i i

i

i

i

=

( ) × =

=

∑

∑

1

12

1

12 (Eq. 10)

Where: 

Eavg = Weighted 12-month rolling average Hg 

emission rate, (lb/MWh); 

ERi = Monthly Hg emission rate, for month 

‘‘i’’, (lb/MWh); and 

n = Number of unit operating hours in month 

‘‘i’’ with valid CEM and electrical output 

data, excluding hours of unit startup, 

shutdown, and malfunction. 

(3) If a sorbent trap monitoring system 

is used in lieu of a Hg CEMS, as 

described in § 75.15 of this chapter and 

in appendix K to part 75 of this chapter, 

calculate the monthly Hg emission rates 

using Equations 7 through 9 of this 

section, except that for a particular pair 

of sorbent traps, Ch in Equation 7 shall 

be the flow-proportional average Hg 

concentration measured over the data 

collection period. 

(i) Daily calibration drift (CD) tests 

and quarterly accuracy determinations 

shall be performed for Hg CEMS in 

accordance with Procedure 1 of 

appendix F to this part. For the CD 

assessments, you may use either 

elemental mercury or mercuric chloride 

(Hg° HgCl2) standards. The four 


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Federal Register / Vol. 72, No. 113 / Wednesday, June 13, 2007 / Rules and Regulations 32741 

quarterly accuracy determinations shall 

consist of one RATA and three 

measurement error (ME) tests using 

HgCl2 standards, as described in section 

8.3 of Performance Specification 12–A 

in appendix B to this part (note: Hg° 

standards may be used if the Hg monitor 

does not have a converter). 

Alternatively, the owner or operator 

may implement the applicable daily, 

weekly, quarterly, and annual quality 

assurance (QA) requirements for Hg 

CEMS in appendix B to part 75 of this 

chapter, in lieu of the QA procedures in 

appendices B and F to this part. Annual 

RATA of sorbent trap monitoring 

systems shall be performed in 

accordance with appendices A and B to 

part 75 of this chapter, and all other 

quality assurance requirements 

specified in appendix K to part 75 of 

this chapter shall be met for sorbent trap 

monitoring systems. 

§ 60.51Da Reporting requirements. 

(a) For SO2, NOX, PM, and Hg 

emissions, the performance test data 

from the initial and subsequent 

performance test and from the 

performance evaluation of the 

continuous monitors (including the 

transmissometer) are submitted to the 

Administrator. 

(b) For SO2 and NOX the following 

information is reported to the 

Administrator for each 24-hour period. 

(1) Calendar date. 

(2) The average SO2 and NOX

emission rates (ng/J or lb/MMBtu) for 

each 30 successive boiler operating 

days, ending with the last 30-day period 

in the quarter; reasons for noncompliance with the emission 

standards; and, description of corrective 

actions taken. 

(3) Percent reduction of the potential 

combustion concentration of SO2 for 

each 30 successive boiler operating 

days, ending with the last 30-day period 

in the quarter; reasons for noncompliance with the standard; and, 

description of corrective actions taken. 

(4) Identification of the boiler 

operating days for which pollutant or 

diluent data have not been obtained by 

an approved method for at least 75 

percent of the hours of operation of the 

facility; justification for not obtaining 

sufficient data; and description of 

corrective actions taken. 

(5) Identification of the times when 

emissions data have been excluded from 

the calculation of average emission rates 

because of startup, shutdown, 

malfunction (NOX only), emergency 

conditions (SO2 only), or other reasons, 

and justification for excluding data for 

reasons other than startup, shutdown, 

malfunction, or emergency conditions. 

(6) Identification of ‘‘F’’ factor used 

for calculations, method of 

determination, and type of fuel 

combusted. 

(7) Identification of times when 

hourly averages have been obtained 

based on manual sampling methods. 

(8) Identification of the times when 

the pollutant concentration exceeded 

full span of the CEMS. 

(9) Description of any modifications 

to CEMS which could affect the ability 

of the CEMS to comply with 

Performance Specifications 2 or 3. 

(c) If the minimum quantity of 

emission data as required by § 60.49Da 

is not obtained for any 30 successive 

boiler operating days, the following 

information obtained under the 

requirements of § 60.48Da(h) is reported 

to the Administrator for that 30-day 

period: 

(1) The number of hourly averages 

available for outlet emission rates (no) 

and inlet emission rates (ni) as 

applicable. 

(2) The standard deviation of hourly 

averages for outlet emission rates (so) 

and inlet emission rates (si) as 

applicable. 

(3) The lower confidence limit for the 

mean outlet emission rate (Eo*) and the 

upper confidence limit for the mean 

inlet emission rate (Ei*) as applicable. 

(4) The applicable potential 

combustion concentration. 

(5) The ratio of the upper confidence 

limit for the mean outlet emission rate 

(Eo*) and the allowable emission rate 

(Estd) as applicable. 

(d) If any standards under § 60.43Da 

are exceeded during emergency 

conditions because of control system 

malfunction, the owner or operator of 

the affected facility shall submit a 

signed statement: 

(1) Indicating if emergency conditions 

existed and requirements under 

§ 60.48Da(d) were met during each 

period, and 

(2) Listing the following information: 

(i) Time periods the emergency 

condition existed; 

(ii) Electrical output and demand on 

the owner or operator’s electric utility 

system and the affected facility; 

(iii) Amount of power purchased from 

interconnected neighboring utility 

companies during the emergency 

period; 

(iv) Percent reduction in emissions 

achieved; 

(v) Atmospheric emission rate (ng/J) 

of the pollutant discharged; and 

(vi) Actions taken to correct control 

system malfunction. 

(e) If fuel pretreatment credit toward 

the SO2 emission standard under 

§ 60.43Da is claimed, the owner or 

operator of the affected facility shall 

submit a signed statement: 

(1) Indicating what percentage 

cleaning credit was taken for the 

calendar quarter, and whether the credit 

was determined in accordance with the 

provisions of § 60.50Da and Method 19 

of appendix A of this part; and 

(2) Listing the quantity, heat content, 

and date each pretreated fuel shipment 

was received during the previous 

quarter; the name and location of the 

fuel pretreatment facility; and the total 

quantity and total heat content of all 

fuels received at the affected facility 

during the previous quarter. 

(f) For any periods for which opacity, 

SO2 or NOX emissions data are not 

available, the owner or operator of the 

affected facility shall submit a signed 

statement indicating if any changes 

were made in operation of the emission 

control system during the period of data 

unavailability. Operations of the control 

system and affected facility during 

periods of data unavailability are to be 

compared with operation of the control 

system and affected facility before and 

following the period of data 

unavailability. 

(g) For Hg, the following information 

shall be reported to the Administrator: 

(1) Company name and address; 

(2) Date of report and beginning and 

ending dates of the reporting period; 

(3) The applicable Hg emission limit 

(lb/MWh); and 

(4) For each month in the reporting 

period: 

(i) The number of unit operating 

hours; 

(ii) The number of unit operating 

hours with valid data for Hg 

concentration, stack gas flow rate, 

moisture (if required), and electrical 

output; 

(iii) The monthly Hg emission rate 

(lb/MWh); 

(iv) The number of hours of valid data 

excluded from the calculation of the 

monthly Hg emission rate, due to unit 

startup, shutdown and malfunction; and 

(v) The 12-month rolling average Hg 

emission rate (lb/MWh); and 

(5) The data assessment report (DAR) 

required by appendix F to this part, or 

an equivalent summary of QA test 

results if the QA of part 75 of this 

chapter are implemented. 

(h) The owner or operator of the 

affected facility shall submit a signed 

statement indicating whether: 

(1) The required CEMS calibration, 

span, and drift checks or other periodic 

audits have or have not been performed 

as specified. 

(2) The data used to show compliance 

was or was not obtained in accordance 

with approved methods and procedures 


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of this part and is representative of plant 

performance. 

(3) The minimum data requirements 

have or have not been met; or, the 

minimum data requirements have not 

been met for errors that were 

unavoidable. 

(4) Compliance with the standards has 

or has not been achieved during the 

reporting period. 

(i) For the purposes of the reports 

required under § 60.7, periods of excess 

emissions are defined as all 6-minute 

periods during which the average 

opacity exceeds the applicable opacity 

standards under § 60.42Da(b). Opacity 

levels in excess of the applicable 

opacity standard and the date of such 

excesses are to be submitted to the 

Administrator each calendar quarter. 

(j) The owner or operator of an 

affected facility shall submit the written 

reports required under this section and 

subpart A to the Administrator 

semiannually for each six-month period. 

All semiannual reports shall be 

postmarked by the 30th day following 

the end of each six-month period. 

(k) The owner or operator of an 

affected facility may submit electronic 

quarterly reports for SO2 and/or NOX

and/or opacity and/or Hg in lieu of 

submitting the written reports required 

under paragraphs (b), (g), and (i) of this 

section. The format of each quarterly 

electronic report shall be coordinated 

with the permitting authority. The 

electronic report(s) shall be submitted 

no later than 30 days after the end of the 

calendar quarter and shall be 

accompanied by a certification 

statement from the owner or operator, 

indicating whether compliance with the 

applicable emission standards and 

minimum data requirements of this 

subpart was achieved during the 

reporting period. Before submitting 

reports in the electronic format, the 

owner or operator shall coordinate with 

the permitting authority to obtain their 

agreement to submit reports in this 

alternative format. 

§ 60.52Da Recordkeeping requirements. 

The owner or operator of an affected 

facility subject to the emissions 

limitations in § 60.45Da shall provide 

notifications in accordance with 

§ 60.7(a) and shall maintain records of 

all information needed to demonstrate 

compliance including performance 

tests, monitoring data, fuel analyses, 

and calculations, consistent with the 

requirements of § 60.7(f). 

Subpart Db—[Amended] 

■ 5. Subpart Db is revised to read as 

follows 

Subpart Db—Standards of Performance for 

Industrial-Commercial-Institutional Steam 

Generating Units 

Sec. 

60.40b Applicability and delegation of 

authority. 

60.41b Definitions. 

60.42b Standard for sulfur dioxide (SO2). 

60.43b Standard for particulate matter (PM). 

60.44b Standard for nitrogen oxides (NOX). 

60.45b Compliance and performance test 

methods and procedures for sulfur 

dioxide. 

60.46b Compliance and performance test 

methods and procedures for particulate 

matter and nitrogen oxides. 

60.47b Emission monitoring for sulfur 

dioxide. 

60.48b Emission monitoring for particulate 

matter and nitrogen oxides. 

60.49b Reporting and recordkeeping 

requirements. 

Subpart Db—Standards of Performance for 

Industrial-Commercial-Institutional Steam 

Generating Units 

§ 60.40b Applicability and delegation of 

authority. 

(a) The affected facility to which this 

subpart applies is each steam generating 

unit that commences construction, 

modification, or reconstruction after 

June 19, 1984, and that has a heat input 

capacity from fuels combusted in the 

steam generating unit of greater than 29 

megawatts (MW) (100 million British 

thermal units per hour (MMBtu/hr)). 

(b) Any affected facility meeting the 

applicability requirements under 

paragraph (a) of this section and 

commencing construction, modification, 

or reconstruction after June 19, 1984, 

but on or before June 19, 1986, is subject 

to the following standards: 

(1) Coal-fired affected facilities having 

a heat input capacity between 29 and 73 

MW (100 and 250 MMBtu/hr), 

inclusive, are subject to the particulate 

matter (PM) and nitrogen oxides (NOX) 

standards under this subpart. 

(2) Coal-fired affected facilities having 

a heat input capacity greater than 73 

MW (250 MMBtu/hr) and meeting the 

applicability requirements under 

subpart D (Standards of performance for 

fossil-fuel-fired steam generators; 

§ 60.40) are subject to the PM and NOX

standards under this subpart and to the 

sulfur dioxide (SO2) standards under 

subpart D (§ 60.43). 

(3) Oil-fired affected facilities having 

a heat input capacity between 29 and 73 

MW (100 and 250 MMBtu/hr), 

inclusive, are subject to the NOX

standards under this subpart. 

(4) Oil-fired affected facilities having 

a heat input capacity greater than 73 

MW (250 MMBtu/hr) and meeting the 

applicability requirements under 

subpart D (Standards of performance for 

fossil-fuel-fired steam generators; 

§ 60.40) are also subject to the NOX

standards under this subpart and the 

PM and SO2 standards under subpart D 

(§ 60.42 and § 60.43). 

(c) Affected facilities that also meet 

the applicability requirements under 

subpart J (Standards of performance for 

petroleum refineries; § 60.104) are 

subject to the PM and NOX standards 

under this subpart and the SO2

standards under subpart J (§ 60.104). 

(d) Affected facilities that also meet 

the applicability requirements under 

subpart E (Standards of performance for 

incinerators; § 60.50) are subject to the 

NOX and PM standards under this 

subpart. 

(e) Steam generating units meeting the 

applicability requirements under 

subpart Da (Standards of performance 

for electric utility steam generating 

units; § 60.40Da) are not subject to this 

subpart. 

(f) Any change to an existing steam 

generating unit for the sole purpose of 

combusting gases containing total 

reduced sulfur (TRS) as defined under 

§ 60.281 is not considered a 

modification under § 60.14 and the 

steam generating unit is not subject to 

this subpart. 

(g) In delegating implementation and 

enforcement authority to a State under 

section 111(c) of the Clean Air Act, the 

following authorities shall be retained 

by the Administrator and not transferred 

to a State. 

(1) Section 60.44b(f). 

(2) Section 60.44b(g). 

(3) Section 60.49b(a)(4). 

(h) Any affected facility that meets the 

applicability requirements and is 

subject to subpart Ea, subpart Eb, or 

subpart AAAA of this part is not 

covered by this subpart. 

(i) Heat recovery steam generators that 

are associated with combined cycle gas 

turbines and that meet the applicability 

requirements of subpart GG or KKKK of 

this part are not subject to this subpart. 

This subpart will continue to apply to 

all other heat recovery steam generators 

that are capable of combusting more 

than 29 MW (100 MMBtu/hr) heat input 

of fossil fuel. If the heat recovery steam 

generator is subject to this subpart, only 

emissions resulting from combustion of 

fuels in the steam generating unit are 

subject to this subpart. (The gas turbine 

emissions are subject to subpart GG or 

KKKK, as applicable, of this part.) 

(j) Any affected facility meeting the 

applicability requirements under 

paragraph (a) of this section and 

commencing construction, modification, 

or reconstruction after June 19, 1986 is 

not subject to subpart D (Standards of 


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Performance for Fossil-Fuel-Fired Steam 

Generators, § 60.40). 

(k) Any affected facility that meets the 

applicability requirements and is 

subject to an EPA approved State or 

Federal section 111(d)/129 plan 

implementing subpart Cb or subpart 

BBBB of this part is not covered by this 

subpart. 

§ 60.41b Definitions. 

As used in this subpart, all terms not 

defined herein shall have the meaning 

given them in the Clean Air Act and in 

subpart A of this part. 

Annual capacity factor means the 

ratio between the actual heat input to a 

steam generating unit from the fuels 

listed in § 60.42b(a), § 60.43b(a), or 

§ 60.44b(a), as applicable, during a 

calendar year and the potential heat 

input to the steam generating unit had 

it been operated for 8,760 hours during 

a calendar year at the maximum steady 

state design heat input capacity. In the 

case of steam generating units that are 

rented or leased, the actual heat input 

shall be determined based on the 

combined heat input from all operations 

of the affected facility in a calendar 

year. 

Byproduct/waste means any liquid or 

gaseous substance produced at chemical 

manufacturing plants, petroleum 

refineries, or pulp and paper mills 

(except natural gas, distillate oil, or 

residual oil) and combusted in a steam 

generating unit for heat recovery or for 

disposal. Gaseous substances with 

carbon dioxide (CO2) levels greater than 

50 percent or carbon monoxide levels 

greater than 10 percent are not 

byproduct/waste for the purpose of this 

subpart. 

Chemical manufacturing plants mean 

industrial plants that are classified by 

the Department of Commerce under 

Standard Industrial Classification (SIC) 

Code 28. 

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), 

coal refuse, and petroleum coke. Coalderived synthetic fuels, including but 

not limited to solvent refined coal, 

gasified coal, coal-oil mixtures, coke 

oven gas, and coal-water mixtures, are 

also included in this definition for the 

purposes of this subpart. 

Coal refuse means any byproduct of 

coal mining or coal cleaning operations 

with an ash content greater than 50 

percent, by weight, and a heating value 

less than 13,900 kJ/kg (6,000 Btu/lb) on 

a dry basis. 

Cogeneration, also known as 

combined heat and power, means a 

facility that simultaneously produces 

both electric (or mechanical) and useful 

thermal energy from the same primary 

energy source. 

Coke oven gas means the volatile 

constituents generated in the gaseous 

exhaust during the carbonization of 

bituminous coal to form coke. 

Combined cycle system means a 

system in which a separate source, such 

as a gas turbine, internal combustion 

engine, kiln, etc., provides exhaust gas 

to a steam generating unit. 

Conventional technology means wet 

flue gas desulfurization (FGD) 

technology, dry FGD technology, 

atmospheric fluidized bed combustion 

technology, and oil 

hydrodesulfurization technology. 

Distillate oil means fuel oils that 

contain 0.05 weight percent nitrogen or 

less and comply with the specifications 

for fuel oil numbers 1 and 2, as defined 

by the American Society of Testing and 

Materials in ASTM D396 (incorporated 

by reference, see § 60.17). 

Dry flue gas desulfurization 

technology means a SO2 control system 

that is located downstream of the steam 

generating unit and removes sulfur 

oxides from the combustion gases of the 

steam generating unit by contacting the 

combustion gases with an alkaline 

reagent and water, whether introduced 

separately or as a premixed slurry or 

solution and forming a dry powder 

material. This definition includes 

devices where the dry powder material 

is subsequently converted to another 

form. Alkaline slurries or solutions used 

in dry flue gas desulfurization 

technology include but are not limited 

to lime and sodium. 

Duct burner means a device that 

combusts fuel and that is placed in the 

exhaust duct from another source, such 

as a stationary gas turbine, internal 

combustion engine, kiln, etc., to allow 

the firing of additional fuel to heat the 

exhaust gases before the exhaust gases 

enter a steam generating unit. 

Emerging technology means any SO2

control system that is not defined as a 

conventional technology under this 

section, and for which the owner or 

operator of the facility has applied to 

the Administrator and received 

approval to operate as an emerging 

technology under § 60.49b(a)(4). 

Federally enforceable means all 

limitations and conditions that are 

enforceable by the Administrator, 

including the requirements of 40 CFR 

parts 60 and 61, requirements within 

any applicable State Implementation 

Plan, and any permit requirements 

established under 40 CFR 52.21 or 

under 40 CFR 51.18 and 51.24. 

Fluidized bed combustion technology 

means combustion of fuel in a bed or 

series of beds (including but not limited 

to bubbling bed units and circulating 

bed units) of limestone aggregate (or 

other sorbent materials) in which these 

materials are forced upward by the flow 

of combustion air and the gaseous 

products of combustion. 

Fuel pretreatment means a process 

that removes a portion of the sulfur in 

a fuel before combustion of the fuel in 

a steam generating unit. 

Full capacity means operation of the 

steam generating unit at 90 percent or 

more of the maximum steady-state 

design heat input capacity. 

Gaseous fuel means any fuel that is 

present as a gas at ISO conditions. 

Gross output means the gross useful 

work performed by the steam generated. 

For units generating only electricity, the 

gross useful work performed is the gross 

electrical output from the turbine/ 

generator set. For cogeneration units, 

the gross useful work performed is the 

gross electrical or mechanical output 

plus 75 percent of the useful thermal 

output measured relative to ISO 

conditions that is not used to generate 

additional electrical or mechanical 

output (i.e., steam delivered to an 

industrial process). 

Heat input means heat derived from 

combustion of fuel in a steam generating 

unit and does not include the heat 

derived from preheated combustion air, 

recirculated flue gases, or exhaust gases 

from other sources, such as gas turbines, 

internal combustion engines, kilns, etc. 

Heat release rate means the steam 

generating unit design heat input 

capacity (in MW or Btu/hr) divided by 

the furnace volume (in cubic meters or 

cubic feet); the furnace volume is that 

volume bounded by the front furnace 

wall where the burner is located, the 

furnace side waterwall, and extending 

to the level just below or in front of the 

first row of convection pass tubes. 

Heat transfer medium means any 

material that is used to transfer heat 

from one point to another point. 

High heat release rate means a heat 

release rate greater than 730,000 J/secm3 (70,000 Btu/hr-ft3). 

ISO Conditions means a temperature 

of 288 Kelvin, a relative humidity of 60 

percent, and a pressure of 101.3 

kilopascals. 

Lignite means a type of coal classified 

as lignite A or lignite B by the American 

Society of Testing and Materials in 

ASTM D388 (incorporated by reference, 

see § 60.17). 

Low heat release rate means a heat 

release rate of 730,000 J/sec-m3 (70,000 

Btu/hr-ft3) or less. 


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Mass-feed stoker steam generating 

unit means a steam generating unit 

where solid fuel is introduced directly 

into a retort or is fed directly onto a 

grate where it is combusted. 

Maximum heat input capacity means 

the ability of a steam generating unit to 

combust a stated maximum amount of 

fuel on a steady state basis, as 

determined by the physical design and 

characteristics of the steam generating 

unit. 

Municipal-type solid waste means 

refuse, more than 50 percent of which 

is waste consisting of a mixture of 

paper, wood, yard wastes, food wastes, 

plastics, leather, rubber, and other 

combustible materials, and 

noncombustible materials such as glass 

and rock. 

Natural gas means: (1) A naturally 

occurring mixture of hydrocarbon and 

nonhydrocarbon gases found in geologic 

formations beneath the earth’s surface, 

of which the principal constituent is 

methane; or (2) liquefied petroleum gas, 

as defined by the American Society for 

Testing and Materials in ASTM D1835 

(incorporated by reference, see § 60.17). 

Noncontinental area means the State 

of Hawaii, the Virgin Islands, Guam, 

American Samoa, the Commonwealth of 

Puerto Rico, or the Northern Mariana 

Islands. 

Oil means crude oil or petroleum or 

a liquid fuel derived from crude oil or 

petroleum, including distillate and 

residual oil. 

Petroleum refinery means industrial 

plants as classified by the Department of 

Commerce under Standard Industrial 

Classification (SIC) Code 29. 

Potential sulfur dioxide emission rate 

means the theoretical SO2 emissions 

(nanograms per joule (ng/J) or lb/ 

MMBtu heat input) that would result 

from combusting fuel in an uncleaned 

state and without using emission 

control systems. 

Process heater means a device that is 

primarily used to heat a material to 

initiate or promote a chemical reaction 

in which the material participates as a 

reactant or catalyst. 

Pulp and paper mills means 

industrial plants that are classified by 

the Department of Commerce under 

North American Industry Classification 

System (NAICS) Code 322 or Standard 

Industrial Classification (SIC) Code 26. 

Pulverized coal-fired steam generating 

unit means a steam generating unit in 

which pulverized coal is introduced 

into an air stream that carries the coal 

to the combustion chamber of the steam 

generating unit where it is fired in 

suspension. This includes both 

conventional pulverized coal-fired and 

micropulverized coal-fired steam 

generating units. Residual oil means 

crude oil, fuel oil numbers 1 and 2 that 

have a nitrogen content greater than 

0.05 weight percent, and all fuel oil 

numbers 4, 5 and 6, as defined by the 

American Society of Testing and 

Materials in ASTM D396 (incorporated 

by reference, see § 60.17). 

Spreader stoker steam generating unit 

means a steam generating unit in which 

solid fuel is introduced to the 

combustion zone by a mechanism that 

throws the fuel onto a grate from above. 

Combustion takes place both in 

suspension and on the grate. 

Steam generating unit means a device 

that combusts any fuel or byproduct/ 

waste and produces steam or heats 

water or any other heat transfer 

medium. This term includes any 

municipal-type solid waste incinerator 

with a heat recovery steam generating 

unit or any steam generating unit that 

combusts fuel and is part of a 

cogeneration system or a combined 

cycle system. This term does not 

include process heaters as they are 

defined in this subpart. 

Steam generating unit operating day 

means a 24-hour period between 12:00 

midnight and the following midnight 

during which any fuel is combusted at 

any time in the steam generating unit. 

It is not necessary for fuel to be 

combusted continuously for the entire 

24-hour period. 

Very low sulfur oil means for units 

constructed, reconstructed, or modified 

on or before February 28, 2005, an oil 

that contains no more than 0.5 weight 

percent sulfur or that, when combusted 

without SO2 emission control, has a SO2

emission rate equal to or less than 215 

ng/J (0.5 lb/MMBtu) heat input. For 

units constructed, reconstructed, or 

modified after February 28, 2005, very 

low sulfur oil means an oil that contains 

no more than 0.3 weight percent sulfur 

or that, when combusted without SO2

emission control, has a SO2 emission 

rate equal to or less than 140 ng/J (0.32 

lb/MMBtu) heat input. 

Wet flue gas desulfurization 

technology means a SO2 control system 

that is located downstream of the steam 

generating unit and removes sulfur 

oxides from the combustion gases of the 

steam generating unit by contacting the 

combustion gas with an alkaline slurry 

or solution and forming a liquid 

material. This definition applies to 

devices where the aqueous liquid 

material product of this contact is 

subsequently converted to other forms. 

Alkaline reagents used in wet flue gas 

desulfurization technology include, but 

are not limited to, lime, limestone, and 

sodium. 

Wet scrubber system means any 

emission control device that mixes an 

aqueous stream or slurry with the 

exhaust gases from a steam generating 

unit to control emissions of PM or SO2. 

Wood means wood, wood residue, 

bark, or any derivative fuel or residue 

thereof, in any form, including, but not 

limited to, sawdust, sanderdust, wood 

chips, scraps, slabs, millings, shavings, 

and processed pellets made from wood 

or other forest residues. 

§ 60.42b Standard for sulfur dioxide (SO2). 

(a) Except as provided in paragraphs 

(b), (c), (d), or (k) of this section, on and 

after the date on which the performance 

test is completed or required to be 

completed under § 60.8, whichever 

comes first, no owner or operator of an 

affected facility that commenced 

construction, reconstruction, or 

modification on or before February 28, 

2005, that combusts coal or oil shall 

cause to be discharged into the 

atmosphere any gases that contain SO2

in excess of 87 ng/J (0.20 lb/MMBtu) or 

10 percent (0.10) of the potential SO2

emission rate (90 percent reduction) and 

the emission limit determined according 

to the following formula: 

E

KH KH

H H s

aa bb

a b

= ( ) +

( ) +

Where: 

Es = SO2 emission limit, in ng/J or lb/MMBtu 

heat input; 

Ka = 520 ng/J (or 1.2 lb/MMBtu); 

Kb = 340 ng/J (or 0.80 lb/MMBtu); 

Ha = Heat input from the combustion of coal, 

in J (MMBtu); and 

Hb = Heat input from the combustion of oil, 

in J (MMBtu). 

Only the heat input supplied to the 

affected facility from the combustion of 

coal and oil is counted under this 

section. No credit is provided for the 

heat input to the affected facility from 

the combustion of natural gas, wood, 

municipal-type solid waste, or other 

fuels or heat derived from exhaust gases 

from other sources, such as gas turbines, 

internal combustion engines, kilns, etc. 

(b) On and after the date on which the 

performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification on or 

before February 28, 2005, that combusts 

coal refuse alone in a fluidized bed 

combustion steam generating unit shall 

cause to be discharged into the 

atmosphere any gases that contain SO2

in excess of 87 ng/J (0.20 lb/MMBtu) or 

20 percent (0.20) of the potential SO2

emission rate (80 percent reduction) and 


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520 ng/J (1.2 lb/MMBtu) heat input. If 

coal or oil is fired with coal refuse, the 

affected facility is subject to paragraph 

(a) or (d) of this section, as applicable. 

(c) On and after the date on which the 

performance test is completed or is 

required to be completed under § 60.8, 

whichever comes first, no owner or 

operator of an affected facility that 

combusts coal or oil, either alone or in 

combination with any other fuel, and 

that uses an emerging technology for the 

control of SO2 emissions, shall cause to 

be discharged into the atmosphere any 

gases that contain SO2 in excess of 50 

percent of the potential SO2 emission 

rate (50 percent reduction) and that 

contain SO2 in excess of the emission 

limit determined according to the 

following formula: 

E

KH KH

H H s

cc dd

c d

= ( ) +

( ) +

Where: 

Es = SO2 emission limit, in ng/J or lb/MM Btu 

heat input; 

Kc = 260 ng/J (or 0.60 lb/MMBtu); 

Kd = 170 ng/J (or 0.40 lb/MMBtu); 

Hc = Heat input from the combustion of coal, 

in J (MMBtu); and 

Hd = Heat input from the combustion of oil, 

in J (MMBtu). 

Only the heat input supplied to the 

affected facility from the combustion of 

coal and oil is counted under this 

section. No credit is provided for the 

heat input to the affected facility from 

the combustion of natural gas, wood, 

municipal-type solid waste, or other 

fuels, or from the heat input derived 

from exhaust gases from other sources, 

such as gas turbines, internal 

combustion engines, kilns, etc. 

(d) On and after the date on which the 

performance test is completed or 

required to be completed under § 60.8, 

whichever comes first, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification on or 

before February 28, 2005 and listed in 

paragraphs (d)(1), (2), (3), or (4) of this 

section shall cause to be discharged into 

the atmosphere any gases that contain 

SO2 in excess of 520 ng/J (1.2 lb/ 

MMBtu) heat input if the affected 

facility combusts coal, or 215 ng/J (0.5 

lb/MMBtu) heat input if the affected 

facility combusts oil other than very low 

sulfur oil. Percent reduction 

requirements are not applicable to 

affected facilities under paragraphs 

(d)(1), (2), (3) or (4) of this section. 

(1) Affected facilities that have an 

annual capacity factor for coal and oil 

of 30 percent (0.30) or less and are 

subject to a federally enforceable permit 

limiting the operation of the affected 

facility to an annual capacity factor for 

coal and oil of 30 percent (0.30) or less; 

(2) Affected facilities located in a 

noncontinental area; or 

(3) Affected facilities combusting coal 

or oil, alone or in combination with any 

fuel, in a duct burner as part of a 

combined cycle system where 30 

percent (0.30) or less of the heat 

entering the steam generating unit is 

from combustion of coal and oil in the 

duct burner and 70 percent (0.70) or 

more of the heat entering the steam 

generating unit is from the exhaust gases 

entering the duct burner; or 

(4) The affected facility burns coke 

oven gas alone or in combination with 

natural gas or very low sulfur distillate 

oil. 

(e) Except as provided in paragraph (f) 

of this section, compliance with the 

emission limits, fuel oil sulfur limits, 

and/or percent reduction requirements 

under this section are determined on a 

30-day rolling average basis. 

(f) Except as provided in paragraph 

(j)(2) of this section, compliance with 

the emission limits or fuel oil sulfur 

limits under this section is determined 

on a 24-hour average basis for affected 

facilities that (1) have a federally 

enforceable permit limiting the annual 

capacity factor for oil to 10 percent or 

less, (2) combust only very low sulfur 

oil, and (3) do not combust any other 

fuel. 

(g) Except as provided in paragraph (i) 

of this section and § 60.45b(a), the SO2

emission limits and percent reduction 

requirements under this section apply at 

all times, including periods of startup, 

shutdown, and malfunction. 

(h) Reductions in the potential SO2

emission rate through fuel pretreatment 

are not credited toward the percent 

reduction requirement under paragraph 

(c) of this section unless: 

(1) Fuel pretreatment results in a 50 

percent or greater reduction in potential 

SO2 emissions and 

(2) Emissions from the pretreated fuel 

(without combustion or postcombustion SO2 control) are equal to or 

less than the emission limits specified 

in paragraph (c) of this section. 

(i) An affected facility subject to 

paragraph (a), (b), or (c) of this section 

may combust very low sulfur oil or 

natural gas when the SO2 control system 

is not being operated because of 

malfunction or maintenance of the SO2

control system. 

(j) Percent reduction requirements are 

not applicable to affected facilities 

combusting only very low sulfur oil. 

The owner or operator of an affected 

facility combusting very low sulfur oil 

shall demonstrate that the oil meets the 

definition of very low sulfur oil by: (1) 

Following the performance testing 

procedures as described in § 60.45b(c) 

or § 60.45b(d), and following the 

monitoring procedures as described in 

§ 60.47b(a) or § 60.47b(b) to determine 

SO2 emission rate or fuel oil sulfur 

content; or (2) maintaining fuel records 

as described in § 60.49b(r). 

(k)(1) Except as provided in 

paragraphs (k)(2), (k)(3), and (k)(4) of 

this section, on and after the date on 

which the initial performance test is 

completed or is required to be 

completed under § 60.8, whichever date 

comes first, no owner or operator of an 

affected facility that commences 

construction, reconstruction, or 

modification after February 28, 2005, 

and that combusts coal, oil, natural gas, 

a mixture of these fuels, or a mixture of 

these fuels with any other fuels shall 

cause to be discharged into the 

atmosphere any gases that contain SO2

in excess of 87 ng/J (0.20 lb/MMBtu) 

heat input or 8 percent (0.08) of the 

potential SO2 emission rate (92 percent 

reduction) and 520 ng/J (1.2 lb/MMBtu) 

heat input. 

(2) Units firing only very low sulfur 

oil and/or a mixture of gaseous fuels 

with a potential SO2 emission rate of 

140 ng/J (0.32 lb/MMBtu) heat input or 

less are exempt from the SO2 emissions 

limit in paragraph 60.42b(k)(1). 

(3) Units that are located in a 

noncontinental area and that combust 

coal or oil shall not discharge any gases 

that contain SO2 in excess of 520 ng/J 

(1.2 lb/MMBtu) heat input if the affected 

facility combusts coal, or 215 ng/J (0.50 

lb/MMBtu) heat input if the affected 

facility combusts oil. 

(4) As an alternative to meeting the 

requirements under paragraph (k)(1) of 

this section, modified facilities that 

combust coal or a mixture of coal with 

other fuels shall not cause to be 

discharged into the atmosphere any 

gases that contain SO2 in excess of 87 

ng/J (0.20 lb/MMBtu) heat input or 10 

percent (0.10) of the potential SO2

emission rate (90 percent reduction) and 

520 ng/J (1.2 lb/MMBtu) heat input. 

§ 60.43b Standard for particulate matter 

(PM). 

(a) On and after the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever comes first, no owner 

or operator of an affected facility that 

commenced construction, 

reconstruction, or modification on or 

before February 28, 2005 that combusts 

coal or combusts mixtures of coal with 

other fuels, shall cause to be discharged 

into the atmosphere from that affected 

facility any gases that contain PM in 

excess of the following emission limits: 


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(1) 22 ng/J (0.051 lb/MMBtu) heat 

input, (i) If the affected facility 

combusts only coal, or 

(ii) If the affected facility combusts 

coal and other fuels and has an annual 

capacity factor for the other fuels of 10 

percent (0.10) or less. 

(2) 43 ng/J (0.10 lb/MMBtu) heat input 

if the affected facility combusts coal and 

other fuels and has an annual capacity 

factor for the other fuels greater than 10 

percent (0.10) and is subject to a 

federally enforceable requirement 

limiting operation of the affected facility 

to an annual capacity factor greater than 

10 percent (0.10) for fuels other than 

coal. 

(3) 86 ng/J (0.20 lb/MMBtu) heat input 

if the affected facility combusts coal or 

coal and other fuels and 

(i) Has an annual capacity factor for 

coal or coal and other fuels of 30 

percent (0.30) or less, 

(ii) Has a maximum heat input 

capacity of 73 MW (250 MMBtu/hr) or 

less, 

(iii) Has a federally enforceable 

requirement limiting operation of the 

affected facility to an annual capacity 

factor of 30 percent (0.30) or less for 

coal or coal and other solid fuels, and 

(iv) Construction of the affected 

facility commenced after June 19, 1984, 

and before November 25, 1986. 

(4) An affected facility burning coke 

oven gas alone or in combination with 

other fuels not subject to a PM standard 

under § 60.43b and not using a postcombustion technology (except a wet 

scrubber) for reducing PM or SO2

emissions is not subject to the PM limits 

under § 60.43b(a). 

(b) On and after the date on which the 

performance test is completed or 

required to be completed under § 60.8, 

whichever comes first, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification on or 

before February 28, 2005, and that 

combusts oil (or mixtures of oil with 

other fuels) and uses a conventional or 

emerging technology to reduce SO2

emissions shall cause to be discharged 

into the atmosphere from that affected 

facility any gases that contain PM in 

excess of 43 ng/J (0.10 lb/MMBtu) heat 

input. 

(c) On and after the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever comes first, no owner 

or operator of an affected facility that 

commenced construction, 

reconstruction, or modification on or 

before February 28, 2005, and that 

combusts wood, or wood with other 

fuels, except coal, shall cause to be 

discharged from that affected facility 

any gases that contain PM in excess of 

the following emission limits: 

(1) 43 ng/J (0.10 lb/MMBtu) heat input 

if the affected facility has an annual 

capacity factor greater than 30 percent 

(0.30) for wood. 

(2) 86 ng/J (0.20 lb/MMBtu) heat input 

if (i) The affected facility has an annual 

capacity factor of 30 percent (0.30) or 

less for wood; 

(ii) Is subject to a federally 

enforceable requirement limiting 

operation of the affected facility to an 

annual capacity factor of 30 percent 

(0.30) or less for wood; and 

(iii) Has a maximum heat input 

capacity of 73 MW (250 MMBtu/hr) or 

less. 

(d) On and after the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that combusts municipal-type solid 

waste or mixtures of municipal-type 

solid waste with other fuels, shall cause 

to be discharged into the atmosphere 

from that affected facility any gases that 

contain PM in excess of the following 

emission limits: 

(1) 43 ng/J (0.10 lb/MMBtu) heat 

input; 

(i) If the affected facility combusts 

only municipal-type solid waste; or 

(ii) If the affected facility combusts 

municipal-type solid waste and other 

fuels and has an annual capacity factor 

for the other fuels of 10 percent (0.10) 

or less. 

(2) 86 ng/J (0.20 lb/MMBtu) heat input 

if the affected facility combusts 

municipal-type solid waste or 

municipal-type solid waste and other 

fuels; and 

(i) Has an annual capacity factor for 

municipal-type solid waste and other 

fuels of 30 percent (0.30) or less; 

(ii) Has a maximum heat input 

capacity of 73 MW (250 MMBtu/hr) or 

less; 

(iii) Has a federally enforceable 

requirement limiting operation of the 

affected facility to an annual capacity 

factor of 30 percent (0.30) or less for 

municipal-type solid waste, or 

municipal-type solid waste and other 

fuels; and 

(iv) Construction of the affected 

facility commenced after June 19, 1984, 

but on or before November 25, 1986. 

(e) For the purposes of this section, 

the annual capacity factor is determined 

by dividing the actual heat input to the 

steam generating unit during the 

calendar year from the combustion of 

coal, wood, or municipal-type solid 

waste, and other fuels, as applicable, by 

the potential heat input to the steam 

generating unit if the steam generating 

unit had been operated for 8,760 hours 

at the maximum heat input capacity. 

(f) On and after the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that combusts coal, oil, wood, or 

mixtures of these fuels with any other 

fuels shall cause to be discharged into 

the atmosphere any gases that exhibit 

greater than 20 percent opacity (6- 

minute average), except for one 6- 

minute period per hour of not more than 

27 percent opacity. 

(g) The PM and opacity standards 

apply at all times, except during periods 

of startup, shutdown or malfunction. 

(h)(1) Except as provided in 

paragraphs (h)(2), (h)(3), (h)(4), and 

(h)(5) of this section, on and after the 

date on which the initial performance 

test is completed or is required to be 

completed under § 60.8, whichever date 

comes first, no owner or operator of an 

affected facility that commenced 

construction, reconstruction, or 

modification after February 28, 2005, 

and that combusts coal, oil, wood, a 

mixture of these fuels, or a mixture of 

these fuels with any other fuels shall 

cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain PM in excess of 

13 ng/J (0.030 lb/MMBtu) heat input, 

(2) As an alternative to meeting the 

requirements of paragraph (h)(1) of this 

section, the owner or operator of an 

affected facility for which modification 

commenced after February 28, 2005, 

may elect to meet the requirements of 

this paragraph. On and after the date on 

which the initial performance test is 

completed or required to be completed 

under § 60.8, no owner or operator of an 

affected facility that commences 

modification after February 28, 2005 

shall cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain PM in excess of 

both: 

(i) 22 ng/J (0.051 lb/MMBtu) heat 

input derived from the combustion of 

coal, oil, wood, a mixture of these fuels, 

or a mixture of these fuels with any 

other fuels; and 

(ii) 0.2 percent of the combustion 

concentration (99.8 percent reduction) 

when combusting coal, oil, wood, a 

mixture of these fuels, or a mixture of 

these fuels with any other fuels. 

(3) On and after the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that commences modification after 

February 28, 2005, and that combusts 

over 30 percent wood (by heat input) on 


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an annual basis and has a maximum 

heat input capacity of 73 MW (250 

MMBtu/h) or less shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain PM in excess of 43 ng/J (0.10 lb/ 

MMBtu) heat input. 

(4) On and after the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that commences modification after 

February 28, 2005, and that combusts 

over 30 percent wood (by heat input) on 

an annual basis and has a maximum 

heat input capacity greater than 73 MW 

(250 MMBtu/h) shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain PM in excess of 37 ng/J (0.085 

lb/MMBtu) heat input. 

(5) On and after the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever date comes first, an 

owner or operator of an affected facility 

that commences construction, 

reconstruction, or modification after 

February 28, 2005, and that combusts 

only oil that contains no more than 0.3 

weight percent sulfur, coke oven gas, a 

mixture of these fuels, or either fuel (or 

a mixture of these fuels) in combination 

with other fuels not subject to a PM 

standard under § 60.43b and not using 

a post-combustion technology (except a 

wet scrubber) to reduce SO2 or PM 

emissions is not subject to the PM limits 

under § 60.43b(h)(1). 

§ 60.44b Standard for nitrogen oxides 

(NOX). 

(a) Except as provided under 

paragraphs (k) and (l) of this section, on 

and after the date on which the initial 

performance test is completed or is 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that is 

subject to the provisions of this section 

and that combusts only coal, oil, or 

natural gas shall cause to be discharged 

into the atmosphere from that affected 

facility any gases that contain NOX

(expressed as NO2) in excess of the 

following emission limits: 

Fuel/steam generating unit type 

Nitrogen oxide emission 

limits (expressed as NO2) 

heat input 

ng/J lb/MMBTu 

(1) Natural gas and distillate oil, except (4): 

(i) Low heat release rate .......................................................................................................................................... 43 0.10 

(ii) High heat release rate ......................................................................................................................................... 86 0.20 

(2) Residual oil: 

(i) Low heat release rate .......................................................................................................................................... 130 0.30 

(ii) High heat release rate ......................................................................................................................................... 170 0.40 

(3) Coal: 

(i) Mass-feed stoker .................................................................................................................................................. 210 0.50 

(ii) Spreader stoker and fluidized bed combustion .................................................................................................. 260 0.60 

(iii) Pulverized coal ................................................................................................................................................... 300 0.70 

(iv) Lignite, except (v) ............................................................................................................................................... 260 0.60 

(v) Lignite mined in North Dakota, South Dakota, or Montana and combusted in a slag tap furnace ................... 340 0.80 

(vi) Coal-derived synthetic fuels ............................................................................................................................... 210 0.50 

(4) Duct burner used in a combined cycle system: 

(i) Natural gas and distillate oil ................................................................................................................................. 86 0.20 

(ii) Residual oil .......................................................................................................................................................... 170 0.40 

(b) Except as provided under 

paragraphs (k) and (l) of this section, on 

and after the date on which the initial 

performance test is completed or is 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

simultaneously combusts mixtures of 

coal, oil, or natural gas shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain NOX in excess of a limit 

determined by the use of the following 

formula: 

E

EL H EL H EL H

HHH n

go go ro ro c c

go ro c

= ( ) + ( ) + ( )

( ) + +

Where: 

En = NOX emission limit (expressed as NO2), 

ng/J (lb/MMBtu); 

ELgo = Appropriate emission limit from 

paragraph (a)(1) for combustion of 

natural gas or distillate oil, ng/J (lb/ 

MMBtu); 

Hgo = Heat input from combustion of natural 

gas or distillate oil, J (MMBtu); 

ELro = Appropriate emission limit from 

paragraph (a)(2) for combustion of 

residual oil, ng/J (lb/MMBtu); 

Hro = Heat input from combustion of residual 

oil, J (MMBtu); 

ELc = Appropriate emission limit from 

paragraph (a)(3) for combustion of coal, 

ng/J (lb/MMBtu); and 

Hc = Heat input from combustion of coal, J 

(MMBtu). 

(c) Except as provided under 

paragraph (l) of this section, on and after 

the date on which the initial 

performance test is completed or is 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

simultaneously combusts coal or oil, or 

a mixture of these fuels with natural gas, 

and wood, municipal-type solid waste, 

or any other fuel shall cause to be 

discharged into the atmosphere any 

gases that contain NOX in excess of the 

emission limit for the coal or oil, or 

mixtures of these fuels with natural gas 

combusted in the affected facility, as 

determined pursuant to paragraph (a) or 

(b) of this section, unless the affected 

facility has an annual capacity factor for 

coal or oil, or mixture of these fuels 

with natural gas of 10 percent (0.10) or 

less and is subject to a federally 

enforceable requirement that limits 

operation of the affected facility to an 

annual capacity factor of 10 percent 

(0.10) or less for coal, oil, or a mixture 

of these fuels with natural gas. 

(d) On and after the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that simultaneously combusts natural 

gas with wood, municipal-type solid 

waste, or other solid fuel, except coal, 

shall cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain NOX in excess of 

130 ng/J (0.30 lb/MMBtu) heat input 

unless the affected facility has an 

annual capacity factor for natural gas of 


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10 percent (0.10) or less and is subject 

to a federally enforceable requirement 

that limits operation of the affected 

facility to an annual capacity factor of 

10 percent (0.10) or less for natural gas. 

(e) Except as provided under 

paragraph (l) of this section, on and after 

the date on which the initial 

performance test is completed or is 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

simultaneously combusts coal, oil, or 

natural gas with byproduct/waste shall 

cause to be discharged into the 

atmosphere any gases that contain NOX

in excess of the emission limit 

determined by the following formula 

unless the affected facility has an 

annual capacity factor for coal, oil, and 

natural gas of 10 percent (0.10) or less 

and is subject to a federally enforceable 

requirement that limits operation of the 

affected facility to an annual capacity 

factor of 10 percent (0.10) or less: 

E

EL H EL H EL H

HHH n

go go ro ro c c

go ro c

= ( ) + ( ) + ( )

( ) + +

Where: 

En = NOX emission limit (expressed as NO2), 

ng/J (lb/MMBtu); 

ELgo = Appropriate emission limit from 

paragraph (a)(1) for combustion of 

natural gas or distillate oil, ng/J (lb/ 

MMBtu); 

Hgo = Heat input from combustion of natural 

gas, distillate oil and gaseous byproduct/ 

waste, J (MMBtu); 

ELro = Appropriate emission limit from 

paragraph (a)(2) for combustion of 

residual oil and/or byproduct/waste, ng/ 

J (lb/MMBtu); 

Hro = Heat input from combustion of residual 

oil, J (MMBtu); 

ELc = Appropriate emission limit from 

paragraph (a)(3) for combustion of coal, 

ng/J (lb/MMBtu); and 

Hc = Heat input from combustion of coal, J 

(MMBtu). 

(f) Any owner or operator of an 

affected facility that combusts 

byproduct/waste with either natural gas 

or oil may petition the Administrator 

within 180 days of the initial startup of 

the affected facility to establish a NOX

emission limit that shall apply 

specifically to that affected facility 

when the byproduct/waste is 

combusted. The petition shall include 

sufficient and appropriate data, as 

determined by the Administrator, such 

as NOX emissions from the affected 

facility, waste composition (including 

nitrogen content), and combustion 

conditions to allow the Administrator to 

confirm that the affected facility is 

unable to comply with the emission 

limits in paragraph (e) of this section 

and to determine the appropriate 

emission limit for the affected facility. 

(1) Any owner or operator of an 

affected facility petitioning for a facilityspecific NOX emission limit under this 

section shall: 

(i) Demonstrate compliance with the 

emission limits for natural gas and 

distillate oil in paragraph (a)(1) of this 

section or for residual oil in paragraph 

(a)(2) or (l)(1) of this section, as 

appropriate, by conducting a 30-day 

performance test as provided in 

§ 60.46b(e). During the performance test 

only natural gas, distillate oil, or 

residual oil shall be combusted in the 

affected facility; and 

(ii) Demonstrate that the affected 

facility is unable to comply with the 

emission limits for natural gas and 

distillate oil in paragraph (a)(1) of this 

section or for residual oil in paragraph 

(a)(2) or (l)(1) of this section, as 

appropriate, when gaseous or liquid 

byproduct/waste is combusted in the 

affected facility under the same 

conditions and using the same 

technological system of emission 

reduction applied when demonstrating 

compliance under paragraph (f)(1)(i) of 

this section. 

(2) The NOX emission limits for 

natural gas or distillate oil in paragraph 

(a)(1) of this section or for residual oil 

in paragraph (a)(2) or (l)(1) of this 

section, as appropriate, shall be 

applicable to the affected facility until 

and unless the petition is approved by 

the Administrator. If the petition is 

approved by the Administrator, a 

facility-specific NOX emission limit will 

be established at the NOX emission level 

achievable when the affected facility is 

combusting oil or natural gas and 

byproduct/waste in a manner that the 

Administrator determines to be 

consistent with minimizing NOX

emissions. In lieu of amending this 

subpart, a letter will be sent to the 

facility describing the facility-specific 

NOX limit. The facility shall use the 

compliance procedures detailed in the 

letter and make the letter available to 

the public. If the Administrator 

determines it is appropriate, the 

conditions and requirements of the 

letter can be reviewed and changed at 

any point. 

(g) Any owner or operator of an 

affected facility that combusts 

hazardous waste (as defined by 40 CFR 

part 261 or 40 CFR part 761) with 

natural gas or oil may petition the 

Administrator within 180 days of the 

initial startup of the affected facility for 

a waiver from compliance with the NOX

emission limit that applies specifically 

to that affected facility. The petition 

must include sufficient and appropriate 

data, as determined by the 

Administrator, on NOX emissions from 

the affected facility, waste destruction 

efficiencies, waste composition 

(including nitrogen content), the 

quantity of specific wastes to be 

combusted and combustion conditions 

to allow the Administrator to determine 

if the affected facility is able to comply 

with the NOX emission limits required 

by this section. The owner or operator 

of the affected facility shall demonstrate 

that when hazardous waste is 

combusted in the affected facility, 

thermal destruction efficiency 

requirements for hazardous waste 

specified in an applicable federally 

enforceable requirement preclude 

compliance with the NOX emission 

limits of this section. The NOX emission 

limits for natural gas or distillate oil in 

paragraph (a)(1) of this section or for 

residual oil in paragraph (a)(2) or (l)(1) 

of this section, as appropriate, are 

applicable to the affected facility until 

and unless the petition is approved by 

the Administrator. (See 40 CFR 761.70 

for regulations applicable to the 

incineration of materials containing 

polychlorinated biphenyls (PCB’s).) In 

lieu of amending this subpart, a letter 

will be sent to the facility describing the 

facility-specific NOX limit. The facility 

shall use the compliance procedures 

detailed in the letter and make the letter 

available to the public. If the 

Administrator determines it is 

appropriate, the conditions and 

requirements of the letter can be 

reviewed and changed at any point. 

(h) For purposes of paragraph (i) of 

this section, the NOX standards under 

this section apply at all times including 

periods of startup, shutdown, or 

malfunction. 

(i) Except as provided under 

paragraph (j) of this section, compliance 

with the emission limits under this 

section is determined on a 30-day 

rolling average basis. 

(j) Compliance with the emission 

limits under this section is determined 

on a 24-hour average basis for the initial 

performance test and on a 3-hour 

average basis for subsequent 

performance tests for any affected 

facilities that: 

(1) Combust, alone or in combination, 

only natural gas, distillate oil, or 

residual oil with a nitrogen content of 

0.30 weight percent or less; 

(2) Have a combined annual capacity 

factor of 10 percent or less for natural 

gas, distillate oil, and residual oil with 

a nitrogen content of 0.30 weight 

percent or less; and 

(3) Are subject to a federally 

enforceable requirement limiting 

operation of the affected facility to the 


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firing of natural gas, distillate oil, and/ 

or residual oil with a nitrogen content 

of 0.30 weight percent or less and 

limiting operation of the affected facility 

to a combined annual capacity factor of 

10 percent or less for natural gas, 

distillate oil, and residual oil with a 

nitrogen content of 0.30 weight percent 

or less. 

(k) Affected facilities that meet the 

criteria described in paragraphs (j)(1), 

(2), and (3) of this section, and that have 

a heat input capacity of 73 MW (250 

MMBtu/hr) or less, are not subject to the 

NOX emission limits under this section. 

(l) On and after the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that commenced construction or 

reconstruction after July 9, 1997 shall 

cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain NOX (expressed 

as NO2) in excess of the following 

limits: 

(1) If the affected facility combusts 

coal, oil, or natural gas, or a mixture of 

these fuels, or with any other fuels: A 

limit of 86 ng/J (0.20 lb/MMBtu) heat 

input unless the affected facility has an 

annual capacity factor for coal, oil, and 

natural gas of 10 percent (0.10) or less 

and is subject to a federally enforceable 

requirement that limits operation of the 

facility to an annual capacity factor of 

10 percent (0.10) or less for coal, oil, 

and natural gas; or 

(2) If the affected facility has a low 

heat release rate and combusts natural 

gas or distillate oil in excess of 30 

percent of the heat input on a 30-day 

rolling average from the combustion of 

all fuels, a limit determined by use of 

the following formula: 

E

H H

H H n

go r

go r

= ( ) × + × ( )

( ) +

0 10 0 20 . .

Where: 

En = NOX emission limit, (lb/MMBtu); 

Hgo = 30-day heat input from combustion of 

natural gas or distillate oil; and 

Hr = 30-day heat input from combustion of 

any other fuel. 

(3) After February 27, 2006, units 

where more than 10 percent of total 

annual output is electrical or 

mechanical may comply with an 

optional limit of 270 ng/J (2.1 lb/MWh) 

gross energy output, based on a 30-day 

rolling average. Units complying with 

this output-based limit must 

demonstrate compliance according to 

the procedures of § 60.48Da(i) of subpart 

Da of this part, and must monitor 

emissions according to § 60.49Da(c), (k), 

through (n) of subpart Da of this part. 

§ 60.45b Compliance and performance test 

methods and procedures for sulfur dioxide. 

(a) The SO2 emission standards under 

§ 60.42b apply at all times. Facilities 

burning coke oven gas alone or in 

combination with any other gaseous 

fuels or distillate oil and complying 

with the fuel based limit under 

§ 60.42b(d) or § 60.42b(k)(2) are allowed 

to exceed the limit 30 operating days 

per calendar year for by-product plant 

maintenance. 

(b) In conducting the performance 

tests required under § 60.8, the owner or 

operator shall use the methods and 

procedures in appendix A (including 

fuel certification and sampling) of this 

part or the methods and procedures as 

specified in this section, except as 

provided in § 60.8(b). Section 60.8(f) 

does not apply to this section. The 30- 

day notice required in § 60.8(d) applies 

only to the initial performance test 

unless otherwise specified by the 

Administrator. 

(c) The owner or operator of an 

affected facility shall conduct 

performance tests to determine 

compliance with the percent of 

potential SO2 emission rate (% Ps) and 

the SO2 emission rate (Es) pursuant to 

§ 60.42b following the procedures listed 

below, except as provided under 

paragraph (d) and (k) of this section. 

(1) The initial performance test shall 

be conducted over 30 consecutive 

operating days of the steam generating 

unit. Compliance with the SO2

standards shall be determined using a 

30-day average. The first operating day 

included in the initial performance test 

shall be scheduled within 30 days after 

achieving the maximum production rate 

at which the affected facility will be 

operated, but not later than 180 days 

after initial startup of the facility. 

(2) If only coal, only oil, or a mixture 

of coal and oil is combusted, the 

following procedures are used: 

(i) The procedures in Method 19 of 

appendix A of this part are used to 

determine the hourly SO2 emission rate 

(Eho) and the 30-day average emission 

rate (Eao). The hourly averages used to 

compute the 30-day averages are 

obtained from the continuous emission 

monitoring system (CEMS) of § 60.47b 

(a) or (b). 

(ii) The percent of potential SO2

emission rate (%Ps) emitted to the 

atmosphere is computed using the 

following formula: 

%

% % PR R s

g f = − 



 



 − 



 



 100 1

100

1

100

Where: 

%Ps = Potential SO2 emission rate, percent; 

%Rg = SO2 removal efficiency of the control 

device as determined by Method 19 of 

appendix A of this part, in percent; and 

%Rf = SO2 removal efficiency of fuel 

pretreatment as determined by Method 

19 of appendix A of this part, in percent. 

(3) If coal or oil is combusted with 

other fuels, the same procedures 

required in paragraph (c)(2) of this 

section are used, except as provided in 

the following: 

(i) An adjusted hourly SO2 emission 

rate (Ehoo) is used in Equation 19–19 of 

Method 19 of appendix A of this part to 

compute an adjusted 30-day average 

emission rate (Eaoo). The Eho° is 

computed using the following formula: 

E

EE X

X ho

o ho w k

k

= − − ( ) 1

Where: 

Ehoo = Adjusted hourly SO2 emission rate, ng/ 

J (lb/MMBtu); 

Eho = Hourly SO2 emission rate, ng/J (lb/ 

MMBtu); 

Ew = SO2 concentration in fuels other than 

coal and oil combusted in the affected 

facility, as determined by the fuel 

sampling and analysis procedures in 

Method 19 of appendix A of this part, 

ng/J (lb/MMBtu). The value Ew for each 

fuel lot is used for each hourly average 

during the time that the lot is being 

combusted; and 

Xk = Fraction of total heat input from fuel 

combustion derived from coal, oil, or 

coal and oil, as determined by applicable 

procedures in Method 19 of appendix A 

of this part. 

(ii) To compute the percent of 

potential SO2 emission rate (%Ps), an 

adjusted %Rg (%Rg

o) is computed from 

the adjusted Eaoo from paragraph 

(b)(3)(i) of this section and an adjusted 

average SO2 inlet rate (Eaio) using the 

following formula: 

% . R

E

E g

o ao

o

ai

o = − 



 



100 1 0 

To compute Eaio, an adjusted hourly 

SO2 inlet rate (Ehio) is used. The Ehio is 

computed using the following formula: 

E

EE X

X hi

o hi w k

k

= − − ( ) 1

Where: 

Ehio = Adjusted hourly SO2 inlet rate, ng/J 

(lb/MMBtu); and 

Ehi = Hourly SO2 inlet rate, ng/J (lb/MMBtu). 

(4) The owner or operator of an 

affected facility subject to paragraph 

(b)(3) of this section does not have to 

measure parameters Ew or Xk if the 

owner or operator elects to assume that 


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32750 Federal Register / Vol. 72, No. 113 / Wednesday, June 13, 2007 / Rules and Regulations 

Xk = 1.0. Owners or operators of affected 

facilities who assume Xk = 1.0 shall: 

(i) Determine %Ps following the 

procedures in paragraph (c)(2) of this 

section; and 

(ii) Sulfur dioxide emissions (Es) are 

considered to be in compliance with 

SO2 emission limits under § 60.42b. 

(5) The owner or operator of an 

affected facility that qualifies under the 

provisions of § 60.42b(d) does not have 

to measure parameters Ew or Xk under 

paragraph (b)(3) of this section if the 

owner or operator of the affected facility 

elects to measure SO2 emission rates of 

the coal or oil following the fuel 

sampling and analysis procedures under 

Method 19 of appendix A of this part. 

(d) Except as provided in paragraph (j) 

of this section, the owner or operator of 

an affected facility that combusts only 

very low sulfur oil, has an annual 

capacity factor for oil of 10 percent 

(0.10) or less, and is subject to a 

federally enforceable requirement 

limiting operation of the affected facility 

to an annual capacity factor for oil of 10 

percent (0.10) or less shall: 

(1) Conduct the initial performance 

test over 24 consecutive steam 

generating unit operating hours at full 

load; 

(2) Determine compliance with the 

standards after the initial performance 

test based on the arithmetic average of 

the hourly emissions data during each 

steam generating unit operating day if a 

CEMS is used, or based on a daily 

average if Method 6B of appendix A of 

this part or fuel sampling and analysis 

procedures under Method 19 of 

appendix A of this part are used. 

(e) The owner or operator of an 

affected facility subject to § 60.42b(d)(1) 

shall demonstrate the maximum design 

capacity of the steam generating unit by 

operating the facility at maximum 

capacity for 24 hours. This 

demonstration will be made during the 

initial performance test and a 

subsequent demonstration may be 

requested at any other time. If the 24- 

hour average firing rate for the affected 

facility is less than the maximum design 

capacity provided by the manufacturer 

of the affected facility, the 24-hour 

average firing rate shall be used to 

determine the capacity utilization rate 

for the affected facility, otherwise the 

maximum design capacity provided by 

the manufacturer is used. 

(f) For the initial performance test 

required under § 60.8, compliance with 

the SO2 emission limits and percent 

reduction requirements under § 60.42b 

is based on the average emission rates 

and the average percent reduction for 

SO2 for the first 30 consecutive steam 

generating unit operating days, except 

as provided under paragraph (d) of this 

section. The initial performance test is 

the only test for which at least 30 days 

prior notice is required unless otherwise 

specified by the Administrator. The 

initial performance test is to be 

scheduled so that the first steam 

generating unit operating day of the 30 

successive steam generating unit 

operating days is completed within 30 

days after achieving the maximum 

production rate at which the affected 

facility will be operated, but not later 

than 180 days after initial startup of the 

facility. The boiler load during the 30- 

day period does not have to be the 

maximum design load, but must be 

representative of future operating 

conditions and include at least one 24- 

hour period at full load. 

(g) After the initial performance test 

required under § 60.8, compliance with 

the SO2 emission limits and percent 

reduction requirements under § 60.42b 

is based on the average emission rates 

and the average percent reduction for 

SO2 for 30 successive steam generating 

unit operating days, except as provided 

under paragraph (d). A separate 

performance test is completed at the end 

of each steam generating unit operating 

day after the initial performance test, 

and a new 30-day average emission rate 

and percent reduction for SO2 are 

calculated to show compliance with the 

standard. 

(h) Except as provided under 

paragraph (i) of this section, the owner 

or operator of an affected facility shall 

use all valid SO2 emissions data in 

calculating %Ps and Eho under 

paragraph (c), of this section whether or 

not the minimum emissions data 

requirements under § 60.46b are 

achieved. All valid emissions data, 

including valid SO2 emission data 

collected during periods of startup, 

shutdown and malfunction, shall be 

used in calculating %Ps and Eho

pursuant to paragraph (c) of this section. 

(i) During periods of malfunction or 

maintenance of the SO2 control systems 

when oil is combusted as provided 

under § 60.42b(i), emission data are not 

used to calculate %Ps or Es under 

§ 60.42b(a), (b) or (c), however, the 

emissions data are used to determine 

compliance with the emission limit 

under § 60.42b(i). 

(j) The owner or operator of an 

affected facility that combusts very low 

sulfur oil is not subject to the 

compliance and performance testing 

requirements of this section if the owner 

or operator obtains fuel receipts as 

described in § 60.49b(r). 

(k) The owner or operator of an 

affected facility seeking to demonstrate 

compliance under §§ 60.42b(d)(4), 

60.42b(j), and 60.42b(k)(2) shall follow 

the applicable procedures under 

§ 60.49b(r). 

§ 60.46b Compliance and performance test 

methods and procedures for particulate 

matter and nitrogen oxides. 

(a) The PM emission standards and 

opacity limits under § 60.43b apply at 

all times except during periods of 

startup, shutdown, or malfunction. The 

NOX emission standards under § 60.44b 

apply at all times. 

(b) Compliance with the PM emission 

standards under § 60.43b shall be 

determined through performance testing 

as described in paragraph (d) of this 

section, except as provided in paragraph 

(i) of this section. 

(c) Compliance with the NOX

emission standards under § 60.44b shall 

be determined through performance 

testing under paragraph (e) or (f), or 

under paragraphs (g) and (h) of this 

section, as applicable. 

(d) To determine compliance with the 

PM emission limits and opacity limits 

under § 60.43b, the owner or operator of 

an affected facility shall conduct an 

initial performance test as required 

under § 60.8, and shall conduct 

subsequent performance tests as 

requested by the Administrator, using 

the following procedures and reference 

methods: 

(1) Method 3B of appendix A of this 

part is used for gas analysis when 

applying Method 5 or 17 of appendix A 

of this part. 

(2) Method 5, 5B, or 17 of appendix 

A of this part shall be used to measure 

the concentration of PM as follows: 

(i) Method 5 of appendix A of this 

part shall be used at affected facilities 

without wet flue gas desulfurization 

(FGD) systems; and 

(ii) Method 17 of appendix A of this 

part may be used at facilities with or 

without wet scrubber systems provided 

the stack gas temperature does not 

exceed a temperature of 160 °C (32 °F). 

The procedures of sections 2.1 and 2.3 

of Method 5B of appendix A of this part 

may be used in Method 17 of appendix 

A of this part only if it is used after a 

wet FGD system. Do not use Method 17 

of appendix A of this part after wet FGD 

systems if the effluent is saturated or 

laden with water droplets. 

(iii) Method 5B of appendix A of this 

part is to be used only after wet FGD 

systems. 

(3) Method 1 of appendix A of this 

part is used to select the sampling site 

and the number of traverse sampling 

points. The sampling time for each run 

is at least 120 minutes and the 

minimum sampling volume is 1.7 dscm 

(60 dscf) except that smaller sampling 


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times or volumes may be approved by 

the Administrator when necessitated by 

process variables or other factors. 

(4) For Method 5 of appendix A of 

this part, the temperature of the sample 

gas in the probe and filter holder is 

monitored and is maintained at 

160±14 °C (320±25 °F). 

(5) For determination of PM 

emissions, the oxygen (O2) or CO2

sample is obtained simultaneously with 

each run of Method 5, 5B, or 17 of 

appendix A of this part by traversing the 

duct at the same sampling location. 

(6) For each run using Method 5, 5B, 

or 17 of appendix A of this part, the 

emission rate expressed in ng/J heat 

input is determined using: 

(i) The O2 or CO2 measurements and 

PM measurements obtained under this 

section; 

(ii) The dry basis F factor; and 

(iii) The dry basis emission rate 

calculation procedure contained in 

Method 19 of appendix A of this part. 

(7) Method 9 of appendix A of this 

part is used for determining the opacity 

of stack emissions. 

(e) To determine compliance with the 

emission limits for NOX required under 

§ 60.44b, the owner or operator of an 

affected facility shall conduct the 

performance test as required under 

§ 60.8 using the continuous system for 

monitoring NOX under § 60.48(b). 

(1) For the initial compliance test, 

NOX from the steam generating unit are 

monitored for 30 successive steam 

generating unit operating days and the 

30-day average emission rate is used to 

determine compliance with the NOX

emission standards under § 60.44b. The 

30-day average emission rate is 

calculated as the average of all hourly 

emissions data recorded by the 

monitoring system during the 30-day 

test period. 

(2) Following the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever date comes first, the 

owner or operator of an affected facility 

which combusts coal or which combusts 

residual oil having a nitrogen content 

greater than 0.30 weight percent shall 

determine compliance with the NOX

emission standards under § 60.44b on a 

continuous basis through the use of a 

30-day rolling average emission rate. A 

new 30-day rolling average emission 

rate is calculated each steam generating 

unit operating day as the average of all 

of the hourly NOX emission data for the 

preceding 30 steam generating unit 

operating days. 

(3) Following the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever date comes first, the 

owner or operator of an affected facility 

that has a heat input capacity greater 

than 73 MW (250 MMBtu/hr) and that 

combusts natural gas, distillate oil, or 

residual oil having a nitrogen content of 

0.30 weight percent or less shall 

determine compliance with the NOX

standards under § 60.44b on a 

continuous basis through the use of a 

30-day rolling average emission rate. A 

new 30-day rolling average emission 

rate is calculated each steam generating 

unit operating day as the average of all 

of the hourly NOX emission data for the 

preceding 30 steam generating unit 

operating days. 

(4) Following 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 of an affected facility that 

has a heat input capacity of 73 MW (250 

MMBtu/hr) or less and that combusts 

natural gas, distillate oil, or residual oil 

having a nitrogen content of 0.30 weight 

percent or less shall upon request 

determine compliance with the NOX

standards under § 60.44b through the 

use of a 30-day performance test. During 

periods when performance tests are not 

requested, NOX emissions data collected 

pursuant to § 60.48b(g)(1) or 

§ 60.48b(g)(2) are used to calculate a 30- 

day rolling average emission rate on a 

daily basis and used to prepare excess 

emission reports, but will not be used to 

determine compliance with the NOX

emission standards. A new 30-day 

rolling average emission rate is 

calculated each steam generating unit 

operating day as the average of all of the 

hourly NOX emission data for the 

preceding 30 steam generating unit 

operating days. 

(5) If the owner or operator of an 

affected facility that combusts residual 

oil does not sample and analyze the 

residual oil for nitrogen content, as 

specified in § 60.49b(e), the 

requirements of § 60.48b(g)(1) apply and 

the provisions of § 60.48b(g)(2) are 

inapplicable. 

(f) To determine compliance with the 

emissions limits for NOX required by 

§ 60.44b(a)(4) or § 60.44b(l) for duct 

burners used in combined cycle 

systems, either of the procedures 

described in paragraph (f)(1) or (2) of 

this section may be used: 

(1) The owner or operator of an 

affected facility shall conduct the 

performance test required under § 60.8 

as follows: 

(i) The emissions rate (E) of NOX shall 

be computed using Equation 1 in this 

section: 

E E

H

H sg E E g

b

= + sg g





 



 ( ) − (Eq.1)

Where: 

E = Emissions rate of NOX from the duct 

burner, ng/J (lb/MMBtu) heat input; 

Esg = Combined effluent emissions rate, in 

ng/J (lb/MMBtu) heat input using 

appropriate F factor as described in 

Method 19 of appendix A of this part; 

Hg = Heat input rate to the combustion 

turbine, in J/hr (MMBtu/hr); 

Hb = Heat input rate to the duct burner, in 

J/hr (MMBtu/hr); and 

Eg = Emissions rate from the combustion 

turbine, in ng/J (lb/MMBtu) heat input 

calculated using appropriate F factor as 

described in Method 19 of appendix A 

of this part. 

(ii) Method 7E of appendix A of this 

part shall be used to determine the NOX

concentrations. Method 3A or 3B of 

appendix A of this part shall be used to 

determine O2 concentration. 

(iii) The owner or operator shall 

identify and demonstrate to the 

Administrator’s satisfaction suitable 

methods to determine the average 

hourly heat input rate to the combustion 

turbine and the average hourly heat 

input rate to the affected duct burner. 

(iv) Compliance with the emissions 

limits under § 60.44b(a)(4) or § 60.44b(l) 

is determined by the three-run average 

(nominal 1-hour runs) for the initial and 

subsequent performance tests; or 

(2) The owner or operator of an 

affected facility may elect to determine 

compliance on a 30-day rolling average 

basis by using the CEMS specified 

under § 60.48b for measuring NOX and 

O2 and meet the requirements of 

§ 60.48b. The sampling site shall be 

located at the outlet from the steam 

generating unit. The NOX emissions rate 

at the outlet from the steam generating 

unit shall constitute the NOX emissions 

rate from the duct burner of the 

combined cycle system. 

(g) The owner or operator of an 

affected facility described in § 60.44b(j) 

or § 60.44b(k) shall demonstrate the 

maximum heat input capacity of the 

steam generating unit by operating the 

facility at maximum capacity for 24 

hours. The owner or operator of an 

affected facility shall determine the 

maximum heat input capacity using the 

heat loss method described in sections 

5 and 7.3 of the ASME Power Test Codes 

4.1 (incorporated by reference, see 

§ 60.17). This demonstration of 

maximum heat input capacity shall be 

made during the initial performance test 

for affected facilities that meet the 

criteria of § 60.44b(j). It shall be made 

within 60 days after achieving the 

maximum production rate at which the 

affected facility will be operated, but not 


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later than 180 days after initial start-up 

of each facility, for affected facilities 

meeting the criteria of § 60.44b(k). 

Subsequent demonstrations may be 

required by the Administrator at any 

other time. If this demonstration 

indicates that the maximum heat input 

capacity of the affected facility is less 

than that stated by the manufacturer of 

the affected facility, the maximum heat 

input capacity determined during this 

demonstration shall be used to 

determine the capacity utilization rate 

for the affected facility. Otherwise, the 

maximum heat input capacity provided 

by the manufacturer is used. 

(h) The owner or operator of an 

affected facility described in § 60.44b(j) 

that has a heat input capacity greater 

than 73 MW (250 MMBtu/hr) shall: 

(1) Conduct an initial performance 

test as required under § 60.8 over a 

minimum of 24 consecutive steam 

generating unit operating hours at 

maximum heat input capacity to 

demonstrate compliance with the NOX

emission standards under § 60.44b using 

Method 7, 7A, 7E of appendix A of this 

part, or other approved reference 

methods; and 

(2) Conduct subsequent performance 

tests once per calendar year or every 400 

hours of operation (whichever comes 

first) to demonstrate compliance with 

the NOX emission standards under 

§ 60.44b over a minimum of 3 

consecutive steam generating unit 

operating hours at maximum heat input 

capacity using Method 7, 7A, 7E of 

appendix A of this part, or other 

approved reference methods. 

(i) The owner or operator of an 

affected facility seeking to demonstrate 

compliance under paragraph 

§ 60.43b(h)(5) shall follow the 

applicable procedures under § 60.49b(r). 

(j) In place of PM testing with EPA 

Reference Method 5, 5B, or 17 of 

appendix A of this part, an owner or 

operator may elect to install, calibrate, 

maintain, and operate a CEMS for 

monitoring PM emissions discharged to 

the atmosphere and record the output of 

the system. The owner or operator of an 

affected facility who elects to 

continuously monitor PM emissions 

instead of conducting performance 

testing using EPA Method 5, 5B, or 17 

of appendix A of this part shall comply 

with the requirements specified in 

paragraphs (j)(1) through (j)(13) of this 

section. 

(1) Notify the Administrator one 

month before starting use of the system. 

(2) Notify the Administrator one 

month before stopping use of the 

system. 

(3) The monitor shall be installed, 

evaluated, and operated in accordance 

with § 60.13 of subpart A of this part. 

(4) The initial performance evaluation 

shall be completed no later than 180 

days after the date of initial startup of 

the affected facility, as specified under 

§ 60.8 of subpart A of this part or within 

180 days of notification to the 

Administrator of use of the CEMS if the 

owner or operator was previously 

determining compliance by Method 5, 

5B, or 17 of appendix A of this part 

performance tests, whichever is later. 

(5) The owner or operator of an 

affected facility shall conduct an initial 

performance test for PM emissions as 

required under § 60.8 of subpart A of 

this part. Compliance with the PM 

emission limit shall be determined by 

using the CEMS specified in paragraph 

(j) of this section to measure PM and 

calculating a 24-hour block arithmetic 

average emission concentration using 

EPA Reference Method 19 of appendix 

A of this part, section 4.1. 

(6) Compliance with the PM emission 

limit shall be determined based on the 

24-hour daily (block) average of the 

hourly arithmetic average emission 

concentrations using CEMS outlet data. 

(7) At a minimum, valid CEMS hourly 

averages shall be obtained as specified 

in paragraphs (j)(7)(i) of this section for 

75 percent of the total operating hours 

per 30-day rolling average. 

(i) At least two data points per hour 

shall be used to calculate each 1-hour 

arithmetic average. 

(ii) [Reserved] 

(8) The 1-hour arithmetic averages 

required under paragraph (j)(7) of this 

section shall be expressed in ng/J or lb/ 

MMBtu heat input and shall be used to 

calculate the boiler operating day daily 

arithmetic average emission 

concentrations. The 1-hour arithmetic 

averages shall be calculated using the 

data points required under § 60.13(e)(2) 

of subpart A of this part. 

(9) All valid CEMS data shall be used 

in calculating average emission 

concentrations even if the minimum 

CEMS data requirements of paragraph 

(j)(7) of this section are not met. 

(10) The CEMS shall be operated 

according to Performance Specification 

11 in appendix B of this part. 

(11) During the correlation testing 

runs of the CEMS required by 

Performance Specification 11 in 

appendix B of this part, PM and O2 (or 

CO2) data shall be collected 

concurrently (or within a 30-to 60- 

minute period) by both the continuous 

emission monitors and the test methods 

specified in paragraphs (j)(7)(i) of this 

section. 

(i) For PM, EPA Reference Method 5, 

5B, or 17 of appendix A of this part 

shall be used. 

(ii) For O2 (or CO2), EPA reference 

Method 3, 3A, or 3B of appendix A of 

this part, as applicable shall be used. 

(12) Quarterly accuracy 

determinations and daily calibration 

drift tests shall be performed in 

accordance with procedure 2 in 

appendix F of this part. Relative 

Response Audit’s must be performed 

annually and Response Correlation 

Audits must be performed every 3 years. 

(13) When PM emissions data are not 

obtained because of CEMS breakdowns, 

repairs, calibration checks, and zero and 

span adjustments, emissions data shall 

be obtained by using other monitoring 

systems as approved by the 

Administrator or EPA Reference Method 

19 of appendix A of this part to provide, 

as necessary, valid emissions data for a 

minimum of 75 percent of total 

operating hours per 30-day rolling 

average. 

§ 60.47b Emission monitoring for sulfur 

dioxide. 

(a) Except as provided in paragraphs 

(b), (f), and (h) of this section, the owner 

or operator of an affected facility subject 

to the SO2 standards under § 60.42b 

shall install, calibrate, maintain, and 

operate CEMS for measuring SO2

concentrations and either O2 or CO2

concentrations and shall record the 

output of the systems. For units 

complying with the percent reduction 

standard, the SO2 and either O2 or CO2

concentrations shall both be monitored 

at the inlet and outlet of the SO2 control 

device. If the owner or operator has 

installed and certified SO2 and O2 or 

CO2 CEMS according to the 

requirements of § 75.20(c)(1) of this 

chapter and appendix A to part 75 of 

this chapter, and is continuing to meet 

the ongoing quality assurance 

requirements of § 75.21 of this chapter 

and appendix B to part 75 of this 

chapter, those CEMS may be used to 

meet the requirements of this section, 

provided that: 

(1) When relative accuracy testing is 

conducted, SO2 concentration data and 

CO2 (or O2) data are collected 

simultaneously; and 

(2) In addition to meeting the 

applicable SO2 and CO2 (or O2) relative 

accuracy specifications in Figure 2 of 

appendix B to part 75 of this chapter, 

the relative accuracy (RA) standard in 

section 13.2 of Performance 

Specification 2 in appendix B to this 

part is met when the RA is calculated 

on a lb/MMBtu basis; and 

(3) The reporting requirements of 

§ 60.49b are met. SO2 and CO2 (or O2) 


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data used to meet the requirements of 

§ 60.49b shall not include substitute 

data values derived from the missing 

data procedures in subpart D of part 75 

of this chapter, nor shall the SO2 data 

have been bias adjusted according to the 

procedures of part 75 of this chapter. 

(b) As an alternative to operating 

CEMS as required under paragraph (a) 

of this section, an owner or operator 

may elect to determine the average SO2

emissions and percent reduction by: 

(1) Collecting coal or oil samples in an 

as-fired condition at the inlet to the 

steam generating unit and analyzing 

them for sulfur and heat content 

according to Method 19 of appendix A 

of this part. Method 19 of appendix A 

of this part provides procedures for 

converting these measurements into the 

format to be used in calculating the 

average SO2 input rate, or 

(2) Measuring SO2 according to 

Method 6B of appendix A of this part 

at the inlet or outlet to the SO2 control 

system. An initial stratification test is 

required to verify the adequacy of the 

Method 6B of appendix A of this part 

sampling location. The stratification test 

shall consist of three paired runs of a 

suitable SO2 and CO2 measurement train 

operated at the candidate location and 

a second similar train operated 

according to the procedures in section 

3.2 and the applicable procedures in 

section 7 of Performance Specification 

2. Method 6B of appendix A of this part, 

Method 6A of appendix A of this part, 

or a combination of Methods 6 and 3 or 

3B of appendix A of this part or 

Methods 6C and 3A of appendix A of 

this part are suitable measurement 

techniques. If Method 6B of appendix A 

of this part is used for the second train, 

sampling time and timer operation may 

be adjusted for the stratification test as 

long as an adequate sample volume is 

collected; however, both sampling trains 

are to be operated similarly. For the 

location to be adequate for Method 6B 

of appendix A of this part 24-hour tests, 

the mean of the absolute difference 

between the three paired runs must be 

less than 10 percent. 

(3) A daily SO2 emission rate, ED, 

shall be determined using the procedure 

described in Method 6A of appendix A 

of this part, section 7.6.2 (Equation 6A–

8) and stated in ng/J (lb/MMBtu) heat 

input. 

(4) The mean 30-day emission rate is 

calculated using the daily measured 

values in ng/J (lb/MMBtu) for 30 

successive steam generating unit 

operating days using equation 19–20 of 

Method 19 of appendix A of this part. 

(c) The owner or operator of an 

affected facility shall obtain emission 

data for at least 75 percent of the 

operating hours in at least 22 out of 30 

successive boiler operating days. If this 

minimum data requirement is not met 

with a single monitoring system, the 

owner or operator of the affected facility 

shall supplement the emission data with 

data collected with other monitoring 

systems as approved by the 

Administrator or the reference methods 

and procedures as described in 

paragraph (b) of this section. 

(d) The 1-hour average SO2 emission 

rates measured by the CEMS required by 

paragraph (a) of this section and 

required under § 60.13(h) is expressed 

in ng/J or lb/MMBtu heat input and is 

used to calculate the average emission 

rates under § 60.42(b). Each 1-hour 

average SO2 emission rate must be based 

on 30 or more minutes of steam 

generating unit operation. The hourly 

averages shall be calculated according to 

§ 60.13(h)(2). Hourly SO2 emission rates 

are not calculated if the affected facility 

is operated less than 30 minutes in a 

given clock hour and are not counted 

toward determination of a steam 

generating unit operating day. 

(e) The procedures under § 60.13 shall 

be followed for installation, evaluation, 

and operation of the CEMS. 

(1) Except as provided for in 

paragraph (e)(4) of this section, all 

CEMS shall be operated in accordance 

with the applicable procedures under 

Performance Specifications 1, 2, and 3 

of appendix B of this part. 

(2) Except as provided for in 

paragraph (e)(4) of this section, 

quarterly accuracy determinations and 

daily calibration drift tests shall be 

performed in accordance with 

Procedure 1 of appendix F of this part. 

(3) For affected facilities combusting 

coal or oil, alone or in combination with 

other fuels, the span value of the SO2

CEMS at the inlet to the SO2 control 

device is 125 percent of the maximum 

estimated hourly potential SO2

emissions of the fuel combusted, and 

the span value of the CEMS at the outlet 

to the SO2 control device is 50 percent 

of the maximum estimated hourly 

potential SO2 emissions of the fuel 

combusted. Alternatively, SO2 span 

values determined according to section 

2.1.1 in appendix A to part 75 of this 

chapter may be used. 

(4) As an alternative to meeting the 

requirements of requirements of 

paragraphs (e)(1) and (e)(2) of this 

section, the owner or operator may elect 

to implement the following alternative 

data accuracy assessment procedures: 

(i) For all required CO2 and O2

monitors and for SO2 and NOX monitors 

with span values less than 100 ppm, the 

daily calibration error test and 

calibration adjustment procedures 

described in sections 2.1.1 and 2.1.3 of 

appendix B to part 75 of this chapter 

may be followed instead of the CD 

assessment procedures in Procedure 1, 

section 4.1 of appendix F to this part. If 

this option is selected, the data 

validation and out-of-control provisions 

in sections 2.1.4 and 2.1.5 of appendix 

B to part 75 of this chapter shall be 

followed instead of the excessive CD 

and out-of-control criteria in Procedure 

1, section 4.3 of appendix F to this part. 

For the purposes of data validation 

under this subpart, the excessive CD 

and out-of-control criteria in Procedure 

1, section 4.3 of appendix F to this part 

shall apply to SO2 and NOX span values 

less than 100 ppm; 

(ii) For all required CO2 and O2

monitors and for SO2 and NOX monitors 

with span values greater than 30 ppm, 

quarterly linearity checks may be 

performed in accordance with section 

2.2.1 of appendix B to part 75 of this 

chapter, instead of performing the 

cylinder gas audits (CGAs) described in 

Procedure 1, section 5.1.2 of appendix 

F to this part. If this option is selected: 

The frequency of the linearity checks 

shall be as specified in section 2.2.1 of 

appendix B to part 75 of this chapter; 

the applicable linearity specifications in 

section 3.2 of appendix A to part 75 of 

this chapter shall be met; the data 

validation and out-of-control criteria in 

section 2.2.3 of appendix B to part 75 

of this chapter shall be followed instead 

of the excessive audit inaccuracy and 

out-of-control criteria in Procedure 1, 

section 5.2 of appendix F to this part; 

and the grace period provisions in 

section 2.2.4 of appendix B to part 75 

of this chapter shall apply. For the 

purposes of data validation under this 

subpart, the cylinder gas audits 

described in Procedure 1, section 5.1.2 

of appendix F to this part shall be 

performed for SO2 and NOX span values 

less than or equal to 30 ppm; and 

(iii) For SO2, CO2, and O2 monitoring 

systems and for NOX emission rate 

monitoring systems, RATAs may be 

performed in accordance with section 

2.3 of appendix B to part 75 of this 

chapter instead of following the 

procedures described in Procedure 1, 

section 5.1.1 of appendix F to this part. 

If this option is selected: The frequency 

of each RATA shall be as specified in 

section 2.3.1 of appendix B to part 75 

of this chapter; the applicable relative 

accuracy specifications shown in Figure 

2 in appendix B to part 75 of this 

chapter shall be met; the data validation 

and out-of-control criteria in section 

2.3.2 of appendix B to part 75 of this 

chapter shall be followed instead of the 

excessive audit inaccuracy and out-ofcontrol criteria in Procedure 1, section 


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5.2 of appendix F to this part; and the 

grace period provisions in section 2.3.3 

of appendix B to part 75 of this chapter 

shall apply. For the purposes of data 

validation under this subpart, the 

relative accuracy specification in 

section 13.2 of Performance 

Specification 2 in appendix B to this 

part shall be met on a lb/MMBtu basis 

for SO2 (regardless of the SO2 emission 

level during the RATA), and for NOX

when the average NOX emission rate 

measured by the reference method 

during the RATA is less than 0.100 lb/ 

MMBtu. 

(f) The owner or operator of an 

affected facility that combusts very low 

sulfur oil or is demonstrating 

compliance under § 60.45b(k) is not 

subject to the emission monitoring 

requirements under paragraph (a) of this 

section if the owner or operator 

maintains fuel records as described in 

§ 60.49b(r). 

§ 60.48b Emission monitoring for 

particulate matter and nitrogen oxides. 

(a) Except as provided in paragraph (j) 

of this section, the owner or operator of 

an affected facility subject to the opacity 

standard under § 60.43b shall install, 

calibrate, maintain, and operate a CEMS 

for measuring the opacity of emissions 

discharged to the atmosphere and 

record the output of the system. 

(b) Except as provided under 

paragraphs (g), (h), and (i) of this 

section, the owner or operator of an 

affected facility subject to a NOX

standard under § 60.44b shall comply 

with either paragraphs (b)(1) or (b)(2) of 

this section. 

(1) Install, calibrate, maintain, and 

operate CEMS for measuring NOX and 

O2 (or CO2) emissions discharged to the 

atmosphere, and shall record the output 

of the system; or 

(2) If the owner or operator has 

installed a NOX emission rate CEMS to 

meet the requirements of part 75 of this 

chapter and is continuing to meet the 

ongoing requirements of part 75 of this 

chapter, that CEMS may be used to meet 

the requirements of this section, except 

that the owner or operator shall also 

meet the requirements of § 60.49b. Data 

reported to meet the requirements of 

§ 60.49b shall not include data 

substituted using the missing data 

procedures in subpart D of part 75 of 

this chapter, nor shall the data have 

been bias adjusted according to the 

procedures of part 75 of this chapter. 

(c) The CEMS required under 

paragraph (b) of this section shall be 

operated and data recorded during all 

periods of operation of the affected 

facility except for CEMS breakdowns 

and repairs. Data is recorded during 

calibration checks, and zero and span 

adjustments. 

(d) The 1-hour average NOX emission 

rates measured by the continuous NOX

monitor required by paragraph (b) of 

this section and required under 

§ 60.13(h) shall be expressed in ng/J or 

lb/MMBtu heat input and shall be used 

to calculate the average emission rates 

under § 60.44b. The 1-hour averages 

shall be calculated using the data points 

required under § 60.13(h)(2). 

(e) The procedures under § 60.13 shall 

be followed for installation, evaluation, 

and operation of the continuous 

monitoring systems. 

(1) For affected facilities combusting 

coal, wood or municipal-type solid 

waste, the span value for a continuous 

monitoring system for measuring 

opacity shall be between 60 and 80 

percent. 

(2) For affected facilities combusting 

coal, oil, or natural gas, the span value 

for NOX is determined using one of the 

following procedures: 

(i) Except as provided under 

paragraph (e)(2)(ii) of this section, NOX

span values shall be determined as 

follows: 

Fuel Span values for NOX

(ppm) 

Natural gas ............... 500. 

Oil ............................. 500. 

Coal .......................... 1,000. 

Mixtures .................... 500 (x + y) + 1,000z. 

Where: 

x = Fraction of total heat input derived from 

natural gas; 

y = Fraction of total heat input derived from 

oil; and 

z = Fraction of total heat input derived from 

coal. 

(ii) As an alternative to meeting the 

requirements of paragraph (e)(2)(i) of 

this section, the owner or operator of an 

affected facility may elect to use the 

NOX span values determined according 

to section 2.1.2 in appendix A to part 75 

of this chapter. 

(3) All span values computed under 

paragraph (e)(2)(i) of this section for 

combusting mixtures of regulated fuels 

are rounded to the nearest 500 ppm. 

Span values computed under paragraph 

(e)(2)(ii) of this section shall be rounded 

off according to section 2.1.2 in 

appendix A to part 75 of this chapter. 

(f) When NOX emission data are not 

obtained because of CEMS breakdowns, 

repairs, calibration checks and zero and 

span adjustments, emission data will be 

obtained by using standby monitoring 

systems, Method 7 of appendix A of this 

part, Method 7A of appendix A of this 

part, or other approved reference 

methods to provide emission data for a 

minimum of 75 percent of the operating 

hours in each steam generating unit 

operating day, in at least 22 out of 30 

successive steam generating unit 

operating days. 

(g) The owner or operator of an 

affected facility that has a heat input 

capacity of 73 MW (250 MMBtu/hr) or 

less, and that has an annual capacity 

factor for residual oil having a nitrogen 

content of 0.30 weight percent or less, 

natural gas, distillate oil, or any mixture 

of these fuels, greater than 10 percent 

(0.10) shall: 

(1) Comply with the provisions of 

paragraphs (b), (c), (d), (e)(2), (e)(3), and 

(f) of this section; or 

(2) Monitor steam generating unit 

operating conditions and predict NOX

emission rates as specified in a plan 

submitted pursuant to § 60.49b(c). 

(h) The owner or operator of a duct 

burner, as described in § 60.41b, that is 

subject to the NOX standards of 

§ 60.44b(a)(4) or § 60.44b(l) is not 

required to install or operate a 

continuous emissions monitoring 

system to measure NOX emissions. 

(i) The owner or operator of an 

affected facility described in § 60.44b(j) 

or § 60.44b(k) is not required to install 

or operate a CEMS for measuring NOX

emissions. 

(j) The owner or operator of an 

affected facility that meets the 

conditions in either paragraph (j)(1), (2), 

(3), (4), or (5) of this section is not 

required to install or operate a COMS 

for measuring opacity if: 

(1) The affected facility uses a PM 

CEMS to monitor PM emissions; or 

(2) The affected facility burns only 

liquid (excluding residual oil) or 

gaseous fuels with potential SO2

emissions rates of 26 ng/J (0.060 lb/ 

MMBtu) or less and does not use a postcombustion technology to reduce SO2 or 

PM emissions. The owner or operator 

must maintain fuel records of the sulfur 

content of the fuels burned, as described 

under § 60.49b(r); or 

(3) The affected facility burns coke 

oven gas alone or in combination with 

fuels meeting the criteria in paragraph 

(j)(2) of this section and does not use a 

post-combustion technology to reduce 

SO2 or PM emissions; or 

(4) The affected facility does not use 

post-combustion technology (except a 

wet scrubber) for reducing PM, SO2, or 

carbon monoxide (CO) emissions, burns 

only gaseous fuels or fuel oils that 

contain less than or equal to 0.30 weight 

percent sulfur, and is operated such that 

emissions of CO to the atmosphere from 

the affected facility are maintained at 

levels less than or equal to 0.15 lb/ 

MMBtu on a steam generating unit 

operating day average basis. Owners and 


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operators of affected facilities electing to 

comply with this paragraph must 

demonstrate compliance according to 

the procedures specified in paragraphs 

(j)(4)(i) through (iv) of this section. 

(i) You must monitor CO emissions 

using a CEMS according to the 

procedures specified in paragraphs 

(j)(4)(i)(A) through (D) of this section. 

(A) The CO CEMS must be installed, 

certified, maintained, and operated 

according to the provisions in 

§ 60.58b(i)(3) of subpart Eb of this part. 

(B) Each 1-hour CO emissions average 

is calculated using the data points 

generated by the CO CEMS expressed in 

parts per million by volume corrected to 

3 percent oxygen (dry basis). 

(C) At a minimum, valid 1-hour CO 

emissions averages must be obtained for 

at least 90 percent of the operating 

hours on a 30-day rolling average basis. 

At least two data points per hour must 

be used to calculate each 1-hour 

average. 

(D) Quarterly accuracy determinations 

and daily calibration drift tests for the 

CO CEMS must be performed in 

accordance with procedure 1 in 

appendix F of this part. 

(ii) You must calculate the 1-hour 

average CO emissions levels for each 

steam generating unit operating day by 

multiplying the average hourly CO 

output concentration measured by the 

CO CEMS times the corresponding 

average hourly flue gas flow rate and 

divided by the corresponding average 

hourly heat input to the affected source. 

The 24-hour average CO emission level 

is determined by calculating the 

arithmetic average of the hourly CO 

emission levels computed for each 

steam generating unit operating day. 

(iii) You must evaluate the preceding 

24-hour average CO emission level each 

steam generating unit operating day 

excluding periods of affected source 

startup, shutdown, or malfunction. If 

the 24-hour average CO emission level 

is greater than 0.15 lb/MMBtu, you must 

initiate investigation of the relevant 

equipment and control systems within 

24 hours of the first discovery of the 

high emission incident and, take the 

appropriate corrective action as soon as 

practicable to adjust control settings or 

repair equipment to reduce the 24-hour 

average CO emission level to 0.15 lb/ 

MMBtu or less. 

(iv) You must record the CO 

measurements and calculations 

performed according to paragraph (j)(4) 

of this section and any corrective 

actions taken. The record of corrective 

action taken must include the date and 

time during which the 24-hour average 

CO emission level was greater than 0.15 

lb/MMBtu, and the date, time, and 

description of the corrective action. 

(5) The affected facility burns only 

gaseous fuels or fuel oils that contain 

less than or equal to 0.30 weight percent 

sulfur and operates according to a 

written site-specific monitoring plan 

approved by the appropriate delegated 

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. 

(k) Owners or operators complying 

with the PM emission limit by using a 

PM CEMS monitor instead of 

monitoring opacity must calibrate, 

maintain, and operate a CEMS, and 

record the output of the system, for PM 

emissions discharged to the atmosphere 

as specified in § 60.46b(j). The CEMS 

specified in paragraph § 60.46b(j) shall 

be operated and data recorded during all 

periods of operation of the affected 

facility except for CEMS breakdowns 

and repairs. Data is recorded during 

calibration checks, and zero and span 

adjustments. 

§ 60.49b Reporting and recordkeeping 

requirements. 

(a) The owner or operator of each 

affected facility shall submit notification 

of the date of initial startup, as provided 

by § 60.7. This notification shall 

include: 

(1) The design heat input capacity of 

the affected facility and identification of 

the fuels to be combusted in the affected 

facility; 

(2) If applicable, a copy of any 

federally enforceable requirement that 

limits the annual capacity factor for any 

fuel or mixture of fuels under 

§§ 60.42b(d)(1), 60.43b(a)(2), (a)(3)(iii), 

(c)(2)(ii), (d)(2)(iii), 60.44b(c), (d), (e), (i), 

(j), (k), 60.45b(d), (g), 60.46b(h), or 

60.48b(i); 

(3) The annual capacity factor at 

which the owner or operator anticipates 

operating the facility based on all fuels 

fired and based on each individual fuel 

fired; and 

(4) Notification that an emerging 

technology will be used for controlling 

emissions of SO2. The Administrator 

will examine the description of the 

emerging technology and will determine 

whether the technology qualifies as an 

emerging technology. In making this 

determination, the Administrator may 

require the owner or operator of the 

affected facility to submit additional 

information concerning the control 

device. The affected facility is subject to 

the provisions of § 60.42b(a) unless and 

until this determination is made by the 

Administrator. 

(b) The owner or operator of each 

affected facility subject to the SO2, PM, 

and/or NOX emission limits under 

§§ 60.42b, 60.43b, and 60.44b shall 

submit to the Administrator the 

performance test data from the initial 

performance test and the performance 

evaluation of the CEMS using the 

applicable performance specifications in 

appendix B of this part. The owner or 

operator of each affected facility 

described in § 60.44b(j) or § 60.44b(k) 

shall submit to the Administrator the 

maximum heat input capacity data from 

the demonstration of the maximum heat 

input capacity of the affected facility. 

(c) The owner or operator of each 

affected facility subject to the NOX

standard of § 60.44b who seeks to 

demonstrate compliance with those 

standards through the monitoring of 

steam generating unit operating 

conditions under the provisions of 

§ 60.48b(g)(2) shall submit to the 

Administrator for approval a plan that 

identifies the operating conditions to be 

monitored under § 60.48b(g)(2) and the 

records to be maintained under 

§ 60.49b(j). This plan shall be submitted 

to the Administrator for approval within 

360 days of the initial startup of the 

affected facility. If the plan is approved, 

the owner or operator shall maintain 

records of predicted nitrogen oxide 

emission rates and the monitored 

operating conditions, including steam 

generating unit load, identified in the 

plan. The plan shall: 

(1) Identify the specific operating 

conditions to be monitored and the 

relationship between these operating 

conditions and NOX emission rates (i.e., 

ng/J or lbs/MMBtu heat input). Steam 

generating unit operating conditions 

include, but are not limited to, the 

degree of staged combustion (i.e., the 

ratio of primary air to secondary and/or 

tertiary air) and the level of excess air 

(i.e., flue gas O2 level); 

(2) Include the data and information 

that the owner or operator used to 

identify the relationship between NOX

emission rates and these operating 

conditions; and 

(3) Identify how these operating 

conditions, including steam generating 

unit load, will be monitored under 

§ 60.48b(g) on an hourly basis by the 

owner or operator during the period of 

operation of the affected facility; the 

quality assurance procedures or 

practices that will be employed to 

ensure that the data generated by 

monitoring these operating conditions 

will be representative and accurate; and 

the type and format of the records of 

these operating conditions, including 

steam generating unit load, that will be 


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maintained by the owner or operator 

under § 60.49b(j). 

(d) The owner or operator of an 

affected facility shall record and 

maintain records of the amounts of each 

fuel combusted during each day and 

calculate the annual capacity factor 

individually for coal, distillate oil, 

residual oil, natural gas, wood, and 

municipal-type solid waste for the 

reporting period. The annual capacity 

factor is determined on a 12-month 

rolling average basis with a new annual 

capacity factor calculated at the end of 

each calendar month. 

(e) For an affected facility that 

combusts residual oil and meets the 

criteria under §§ 60.46b(e)(4), 60.44b(j), 

or (k), the owner or operator shall 

maintain records of the nitrogen content 

of the residual oil combusted in the 

affected facility and calculate the 

average fuel nitrogen content for the 

reporting period. The nitrogen content 

shall be determined using ASTM 

Method D4629 (incorporated by 

reference, see § 60.17), or fuel suppliers. 

If residual oil blends are being 

combusted, fuel nitrogen specifications 

may be prorated based on the ratio of 

residual oils of different nitrogen 

content in the fuel blend. 

(f) For facilities subject to the opacity 

standard under § 60.43b, the owner or 

operator shall maintain records of 

opacity. 

(g) Except as provided under 

paragraph (p) of this section, the owner 

or operator of an affected facility subject 

to the NOX standards under § 60.44b 

shall maintain records of the following 

information for each steam generating 

unit operating day: 

(1) Calendar date; 

(2) The average hourly NOX emission 

rates (expressed as NO2) (ng/J or lb/ 

MMBtu heat input) measured or 

predicted; 

(3) The 30-day average NOX emission 

rates (ng/J or lb/MMBtu heat input) 

calculated at the end of each steam 

generating unit operating day from the 

measured or predicted hourly nitrogen 

oxide emission rates for the preceding 

30 steam generating unit operating days; 

(4) Identification of the steam 

generating unit operating days when the 

calculated 30-day average NOX emission 

rates are in excess of the NOX emissions 

standards under § 60.44b, with the 

reasons for such excess emissions as 

well as a description of corrective 

actions taken; 

(5) Identification of the steam 

generating unit operating days for which 

pollutant data have not been obtained, 

including reasons for not obtaining 

sufficient data and a description of 

corrective actions taken; 

(6) Identification of the times when 

emission data have been excluded from 

the calculation of average emission rates 

and the reasons for excluding data; 

(7) Identification of ‘‘F’’ factor used 

for calculations, method of 

determination, and type of fuel 

combusted; 

(8) Identification of the times when 

the pollutant concentration exceeded 

full span of the CEMS; 

(9) Description of any modifications 

to the CEMS that could affect the ability 

of the CEMS to comply with 

Performance Specification 2 or 3; and 

(10) Results of daily CEMS drift tests 

and quarterly accuracy assessments as 

required under appendix F, Procedure 1 

of this part. 

(h) The owner or operator of any 

affected facility in any category listed in 

paragraphs (h)(1) or (2) of this section is 

required to submit excess emission 

reports for any excess emissions that 

occurred during the reporting period. 

(1) Any affected facility subject to the 

opacity standards under § 60.43b(e) or 

to the operating parameter monitoring 

requirements under § 60.13(i)(1). 

(2) Any affected facility that is subject 

to the NOX standard of § 60.44b, and 

that: 

(i) Combusts natural gas, distillate oil, 

or residual oil with a nitrogen content 

of 0.3 weight percent or less; or 

(ii) Has a heat input capacity of 73 

MW (250 MMBtu/hr) or less and is 

required to monitor NOX emissions on 

a continuous basis under § 60.48b(g)(1) 

or steam generating unit operating 

conditions under § 60.48b(g)(2). 

(3) For the purpose of § 60.43b, excess 

emissions are defined as all 6-minute 

periods during which the average 

opacity exceeds the opacity standards 

under § 60.43b(f). 

(4) For purposes of § 60.48b(g)(1), 

excess emissions are defined as any 

calculated 30-day rolling average NOX

emission rate, as determined under 

§ 60.46b(e), that exceeds the applicable 

emission limits in § 60.44b. 

(i) The owner or operator of any 

affected facility subject to the 

continuous monitoring requirements for 

NOX under § 60.48(b) shall submit 

reports containing the information 

recorded under paragraph (g) of this 

section. 

(j) The owner or operator of any 

affected facility subject to the SO2

standards under § 60.42b shall submit 

reports. 

(k) For each affected facility subject to 

the compliance and performance testing 

requirements of § 60.45b and the 

reporting requirement in paragraph (j) of 

this section, the following information 

shall be reported to the Administrator: 

(1) Calendar dates covered in the 

reporting period; 

(2) Each 30-day average SO2 emission 

rate (ng/J or lb/MMBtu heat input) 

measured during the reporting period, 

ending with the last 30-day period; 

reasons for noncompliance with the 

emission standards; and a description of 

corrective actions taken; 

(3) Each 30-day average percent 

reduction in SO2 emissions calculated 

during the reporting period, ending with 

the last 30-day period; reasons for 

noncompliance with the emission 

standards; and a description of 

corrective actions taken; 

(4) Identification of the steam 

generating unit operating days that coal 

or oil was combusted and for which SO2

or diluent (O2 or CO2) data have not 

been obtained by an approved method 

for at least 75 percent of the operating 

hours in the steam generating unit 

operating day; justification for not 

obtaining sufficient data; and 

description of corrective action taken; 

(5) Identification of the times when 

emissions data have been excluded from 

the calculation of average emission 

rates; justification for excluding data; 

and description of corrective action 

taken if data have been excluded for 

periods other than those during which 

coal or oil were not combusted in the 

steam generating unit; 

(6) Identification of ‘‘F’’ factor used 

for calculations, method of 

determination, and type of fuel 

combusted; 

(7) Identification of times when 

hourly averages have been obtained 

based on manual sampling methods; 

(8) Identification of the times when 

the pollutant concentration exceeded 

full span of the CEMS; 

(9) Description of any modifications 

to the CEMS that could affect the ability 

of the CEMS to comply with 

Performance Specification 2 or 3; 

(10) Results of daily CEMS drift tests 

and quarterly accuracy assessments as 

required under appendix F, Procedure 1 

of this part; and 

(11) The annual capacity factor of 

each fired as provided under paragraph 

(d) of this section. 

(l) For each affected facility subject to 

the compliance and performance testing 

requirements of § 60.45b(d) and the 

reporting requirements of paragraph (j) 

of this section, the following 

information shall be reported to the 

Administrator: 

(1) Calendar dates when the facility 

was in operation during the reporting 

period; 

(2) The 24-hour average SO2 emission 

rate measured for each steam generating 

unit operating day during the reporting 


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period that coal or oil was combusted, 

ending in the last 24-hour period in the 

quarter; reasons for noncompliance with 

the emission standards; and a 

description of corrective actions taken; 

(3) Identification of the steam 

generating unit operating days that coal 

or oil was combusted for which S02 or 

diluent (O2 or CO2) data have not been 

obtained by an approved method for at 

least 75 percent of the operating hours; 

justification for not obtaining sufficient 

data; and description of corrective 

action taken; 

(4) Identification of the times when 

emissions data have been excluded from 

the calculation of average emission 

rates; justification for excluding data; 

and description of corrective action 

taken if data have been excluded for 

periods other than those during which 

coal or oil were not combusted in the 

steam generating unit; 

(5) Identification of ‘‘F’’ factor used 

for calculations, method of 

determination, and type of fuel 

combusted; 

(6) Identification of times when 

hourly averages have been obtained 

based on manual sampling methods; 

(7) Identification of the times when 

the pollutant concentration exceeded 

full span of the CEMS; 

(8) Description of any modifications 

to the CEMS that could affect the ability 

of the CEMS to comply with 

Performance Specification 2 or 3; and 

(9) Results of daily CEMS drift tests 

and quarterly accuracy assessments as 

required under Procedure 1 of appendix 

F 1 of this part. If the owner or operator 

elects to implement the alternative data 

assessment procedures described in 

§§ 60.47b(e)(4)(i) through (e)(4)(iii), each 

data assessment report shall include a 

summary of the results of all of the 

RATAs, linearity checks, CGAs, and 

calibration error or drift assessments 

required by §§ 60.47b(e)(4)(i) through 

(e)(4)(iii). 

(m) For each affected facility subject 

to the SO2 standards under § 60.42(b) for 

which the minimum amount of data 

required under § 60.47b(f) were not 

obtained during the reporting period, 

the following information is reported to 

the Administrator in addition to that 

required under paragraph (k) of this 

section: 

(1) The number of hourly averages 

available for outlet emission rates and 

inlet emission rates; 

(2) The standard deviation of hourly 

averages for outlet emission rates and 

inlet emission rates, as determined in 

Method 19 of appendix A of this part, 

section 7; 

(3) The lower confidence limit for the 

mean outlet emission rate and the upper 

confidence limit for the mean inlet 

emission rate, as calculated in Method 

19 of appendix A of this part, section 7; 

and 

(4) The ratio of the lower confidence 

limit for the mean outlet emission rate 

and the allowable emission rate, as 

determined in Method 19 of appendix A 

of this part, section 7. 

(n) If a percent removal efficiency by 

fuel pretreatment (i.e., %Rf) is used to 

determine the overall percent reduction 

(i.e., %Ro) under § 60.45b, the owner or 

operator of the affected facility shall 

submit a signed statement with the 

report. 

(1) Indicating what removal efficiency 

by fuel pretreatment (i.e., %Rf) was 

credited during the reporting period; 

(2) Listing the quantity, heat content, 

and date each pre-treated fuel shipment 

was received during the reporting 

period, the name and location of the 

fuel pretreatment facility; and the total 

quantity and total heat content of all 

fuels received at the affected facility 

during the reporting period; 

(3) Documenting the transport of the 

fuel from the fuel pretreatment facility 

to the steam generating unit; and 

(4) Including a signed statement from 

the owner or operator of the fuel 

pretreatment facility certifying that the 

percent removal efficiency achieved by 

fuel pretreatment was determined in 

accordance with the provisions of 

Method 19 of appendix A of this part 

and listing the heat content and sulfur 

content of each fuel before and after fuel 

pretreatment. 

(o) All records required under this 

section shall be maintained by the 

owner or operator of the affected facility 

for a period of 2 years following the date 

of such record. 

(p) The owner or operator of an 

affected facility described in § 60.44b(j) 

or (k) shall maintain records of the 

following information for each steam 

generating unit operating day: 

(1) Calendar date; 

(2) The number of hours of operation; 

and 

(3) A record of the hourly steam load. 

(q) The owner or operator of an 

affected facility described in § 60.44b(j) 

or § 60.44b(k) shall submit to the 

Administrator a report containing: 

(1) The annual capacity factor over 

the previous 12 months; 

(2) The average fuel nitrogen content 

during the reporting period, if residual 

oil was fired; and 

(3) If the affected facility meets the 

criteria described in § 60.44b(j), the 

results of any NOX emission tests 

required during the reporting period, 

the hours of operation during the 

reporting period, and the hours of 

operation since the last NOX emission 

test. 

(r) The owner or operator of an 

affected facility who elects to use the 

fuel based compliance alternatives in 

§ 60.42b or § 60.43b shall either: 

(1) The owner or operator of an 

affected facility who elects to 

demonstrate that the affected facility 

combusts only very low sulfur oil under 

§ 60.42b(j)(2) or § 60.42b(k)(2) shall 

obtain and maintain at the affected 

facility fuel receipts from the fuel 

supplier that certify that the oil meets 

the definition of distillate oil as defined 

in § 60.41b and the applicable sulfur 

limit. For the purposes of this section, 

the distillate oil need not meet the fuel 

nitrogen content specification in the 

definition of distillate oil. Reports shall 

be submitted to the Administrator 

certifying that only very low sulfur oil 

meeting this definition and/or pipeline 

quality natural gas was combusted in 

the affected facility during the reporting 

period; or 

(2) The owner or operator of an 

affected facility who elects to 

demonstrate compliance based on fuel 

analysis in § 60.42b or § 60.43b shall 

develop and submit a site-specific fuel 

analysis plan to the Administrator for 

review and approval no later than 60 

days before the date you intend to 

demonstrate compliance. Each fuel 

analysis plan shall include a minimum 

initial requirement of weekly testing 

and each analysis report shall contain, 

at a minimum, the following 

information: 

(i) The potential sulfur emissions rate 

of the representative fuel mixture in ng/ 

J heat input; 

(ii) The method used to determine the 

potential sulfur emissions rate of each 

constituent of the mixture. For distillate 

oil and natural gas a fuel receipt or tariff 

sheet is acceptable; 

(iii) The ratio of different fuels in the 

mixture; and 

(iv) The owner or operator can 

petition the Administrator to approve 

monthly or quarterly sampling in place 

of weekly sampling. 

(s) Facility specific NOX standard for 

Cytec Industries Fortier Plant’s C.AOG 

incinerator located in Westwego, 

Louisiana: 

(1) Definitions. 

Oxidation zone is defined as the 

portion of the C.AOG incinerator that 

extends from the inlet of the oxidizing 

zone combustion air to the outlet gas 

stack. 

Reducing zone is defined as the 

portion of the C.AOG incinerator that 

extends from the burner section to the 

inlet of the oxidizing zone combustion 

air. 


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Total inlet air is defined as the total 

amount of air introduced into the 

C.AOG incinerator for combustion of 

natural gas and chemical by-product 

waste and is equal to the sum of the air 

flow into the reducing zone and the air 

flow into the oxidation zone. 

(2) Standard for nitrogen oxides. (i) 

When fossil fuel alone is combusted, the 

NOX emission limit for fossil fuel in 

§ 60.44b(a) applies. 

(ii) When natural gas and chemical 

by-product waste are simultaneously 

combusted, the NOX emission limit is 

289 ng/J (0.67 lb/MMBtu) and a 

maximum of 81 percent of the total inlet 

air provided for combustion shall be 

provided to the reducing zone of the 

C.AOG incinerator. 

(3) Emission monitoring. (i) The 

percent of total inlet air provided to the 

reducing zone shall be determined at 

least every 15 minutes by measuring the 

air flow of all the air entering the 

reducing zone and the air flow of all the 

air entering the oxidation zone, and 

compliance with the percentage of total 

inlet air that is provided to the reducing 

zone shall be determined on a 3-hour 

average basis. 

(ii) The NOX emission limit shall be 

determined by the compliance and 

performance test methods and 

procedures for NOX in § 60.46b(i). 

(iii) The monitoring of the NOX

emission limit shall be performed in 

accordance with § 60.48b. 

(4) Reporting and recordkeeping 

requirements. (i) The owner or operator 

of the C.AOG incinerator shall submit a 

report on any excursions from the limits 

required by paragraph (a)(2) of this 

section to the Administrator with the 

quarterly report required by paragraph 

(i) of this section. 

(ii) The owner or operator of the 

C.AOG incinerator shall keep records of 

the monitoring required by paragraph 

(a)(3) of this section for a period of 2 

years following the date of such record. 

(iii) The owner of operator of the 

C.AOG incinerator shall perform all the 

applicable reporting and recordkeeping 

requirements of this section. 

(t) Facility-specific NOX standard for 

Rohm and Haas Kentucky 

Incorporated’s Boiler No. 100 located in 

Louisville, Kentucky: 

(1) Definitions. 

Air ratio control damper is defined as 

the part of the low NOX burner that is 

adjusted to control the split of total 

combustion air delivered to the 

reducing and oxidation portions of the 

combustion flame. 

Flue gas recirculation line is defined 

as the part of Boiler No. 100 that 

recirculates a portion of the boiler flue 

gas back into the combustion air. 

(2) Standard for nitrogen oxides. (i) 

When fossil fuel alone is combusted, the 

NOX emission limit for fossil fuel in 

§ 60.44b(a) applies. 

(ii) When fossil fuel and chemical byproduct waste are simultaneously 

combusted, the NOX emission limit is 

473 ng/J (1.1 lb/MMBtu), and the air 

ratio control damper tee handle shall be 

at a minimum of 5 inches (12.7 

centimeters) out of the boiler, and the 

flue gas recirculation line shall be 

operated at a minimum of 10 percent 

open as indicated by its valve opening 

position indicator. 

(3) Emission monitoring for nitrogen 

oxides. (i) The air ratio control damper 

tee handle setting and the flue gas 

recirculation line valve opening 

position indicator setting shall be 

recorded during each 8-hour operating 

shift. 

(ii) The NOX emission limit shall be 

determined by the compliance and 

performance test methods and 

procedures for NOX in § 60.46b. 

(iii) The monitoring of the NOX

emission limit shall be performed in 

accordance with § 60.48b. 

(4) Reporting and recordkeeping 

requirements. (i) The owner or operator 

of Boiler No. 100 shall submit a report 

on any excursions from the limits 

required by paragraph (b)(2) of this 

section to the Administrator with the 

quarterly report required by § 60.49b(i). 

(ii) The owner or operator of Boiler 

No. 100 shall keep records of the 

monitoring required by paragraph (b)(3) 

of this section for a period of 2 years 

following the date of such record. 

(iii) The owner of operator of Boiler 

No. 100 shall perform all the applicable 

reporting and recordkeeping 

requirements of § 60.49b. 

(u) Site-specific standard for Merck & 

Co., Inc.’s Stonewall Plant in Elkton, 

Virginia. (1) This paragraph (u) applies 

only to the pharmaceutical 

manufacturing facility, commonly 

referred to as the Stonewall Plant, 

located at Route 340 South, in Elkton, 

Virginia (‘‘site’’) and only to the natural 

gas-fired boilers installed as part of the 

powerhouse conversion required 

pursuant to 40 CFR 52.2454(g). The 

requirements of this paragraph shall 

apply, and the requirements of 

§§ 60.40b through 60.49b(t) shall not 

apply, to the natural gas-fired boilers 

installed pursuant to 40 CFR 52.2454(g). 

(i) The site shall equip the natural gasfired boilers with low NOX technology. 

(ii) The site shall install, calibrate, 

maintain, and operate a continuous 

monitoring and recording system for 

measuring NOX emissions discharged to 

the atmosphere and opacity using a 

continuous emissions monitoring 

system or a predictive emissions 

monitoring system. 

(iii) Within 180 days of the 

completion of the powerhouse 

conversion, as required by 40 CFR 

52.2454, the site shall perform a 

performance test to quantify criteria 

pollutant emissions. 

(2) [Reserved] 

(v) The owner or operator of an 

affected facility may submit electronic 

quarterly reports for SO2 and/or NOX

and/or opacity in lieu of submitting the 

written reports required under 

paragraphs (h), (i), (j), (k) or (l) of this 

section. The format of each quarterly 

electronic report shall be coordinated 

with the permitting authority. The 

electronic report(s) shall be submitted 

no later than 30 days after the end of the 

calendar quarter and shall be 

accompanied by a certification 

statement from the owner or operator, 

indicating whether compliance with the 

applicable emission standards and 

minimum data requirements of this 

subpart was achieved during the 

reporting period. Before submitting 

reports in the electronic format, the 

owner or operator shall coordinate with 

the permitting authority to obtain their 

agreement to submit reports in this 

alternative format. 

(w) The reporting period for the 

reports required under this subpart is 

each 6 month period. All reports shall 

be submitted to the Administrator and 

shall be postmarked by the 30th day 

following the end of the reporting 

period. 

(x) Facility-specific NOX standard for 

Weyerhaeuser Company’s No. 2 Power 

Boiler located in New Bern, North 

Carolina: 

(1) Standard for nitrogen oxides. (i) 

When fossil fuel alone is combusted, the 

NOX emission limit for fossil fuel in 

§ 60.44b(a) applies. 

(ii) When fossil fuel and chemical byproduct waste are simultaneously 

combusted, the NOX emission limit is 

215 ng/J (0.5 lb/MMBtu). 

(2) Emission monitoring for nitrogen 

oxides. (i) The NOX emissions shall be 

determined by the compliance and 

performance test methods and 

procedures for NOX in § 60.46b. 

(ii) The monitoring of the NOX

emissions shall be performed in 

accordance with § 60.48b. 

(3) Reporting and recordkeeping 

requirements. (i) The owner or operator 

of the No. 2 Power Boiler shall submit 

a report on any excursions from the 

limits required by paragraph (x)(2) of 

this section to the Administrator with 

the quarterly report required by 

§ 60.49b(i). 


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(ii) The owner or operator of the No. 

2 Power Boiler shall keep records of the 

monitoring required by paragraph (x)(3) 

of this section for a period of 2 years 

following the date of such record. 

(iii) The owner or operator of the No. 

2 Power Boiler shall perform all the 

applicable reporting and recordkeeping 

requirements of § 60.49b. 

(y) Facility-specific NOX standard for 

INEOS USA’s AOGI located in Lima, 

Ohio: 

(1) Standard for NOX. (i) When fossil 

fuel alone is combusted, the NOX

emission limit for fossil fuel in 

§ 60.44b(a) applies. 

(ii) When fossil fuel and chemical 

byproduct/waste are simultaneously 

combusted, the NOX emission limit is 

645 ng/J (1.5 lb/MMBtu). 

(2) Emission monitoring for NOX. (i) 

The NOX emissions shall be determined 

by the compliance and performance test 

methods and procedures for NOX in 

§ 60.46b. 

(ii) The monitoring of the NOX

emissions shall be performed in 

accordance with § 60.48b. 

(3) Reporting and recordkeeping 

requirements. (i) The owner or operator 

of the AOGI shall submit a report on any 

excursions from the limits required by 

paragraph (y)(2) of this section to the 

Administrator with the quarterly report 

required by paragraph (i) of this section. 

(ii) The owner or operator of the AOGI 

shall keep records of the monitoring 

required by paragraph (y)(3) of this 

section for a period of 2 years following 

the date of such record. 

(iii) The owner or operator of the 

AOGI shall perform all the applicable 

reporting and recordkeeping 

requirements of this section. 

Subpart Dc—[Amended] 

■ 6. Subpart Dc is revised to read as 

follows: 

Subpart Dc—Standards of Performance for 

Small Industrial-Commercial-Institutional 

Steam Generating Units 

Sec. 

60.40c Applicability and delegation of 

authority. 

60.41c Definitions. 

60.42c Standard for sulfur dioxide (SO2). 

60.43c Standard for particulate matter (PM). 

60.44c Compliance and performance test 

methods and procedures for sulfur 

dioxide. 

60.45c Compliance and performance test 

methods and procedures for particulate 

matter. 

60.46c Emission monitoring for sulfur 

dioxide. 

60.47c Emission monitoring for particulate 

matter. 

60.48c Reporting and recordkeeping 

requirements. 

Subpart Dc—Standards of 

Performance for Small IndustrialCommercial-Institutional Steam 

Generating Units 

§ 60.40c Applicability and delegation of 

authority. 

(a) Except as provided in paragraph 

(d) of this section, the affected facility 

to which this subpart applies is each 

steam generating unit for which 

construction, modification, or 

reconstruction is commenced after June 

9, 1989 and that has a maximum design 

heat input capacity of 29 megawatts 

(MW) (100 million British thermal units 

per hour (MMBtu/hr)) or less, but 

greater than or equal to 2.9 MW (10 

MMBtu/hr). 

(b) In delegating implementation and 

enforcement authority to a State under 

section 111(c) of the Clean Air Act, 

§ 60.48c(a)(4) shall be retained by the 

Administrator and not transferred to a 

State. 

(c) Steam generating units that meet 

the applicability requirements in 

paragraph (a) of this section are not 

subject to the sulfur dioxide (SO2) or 

particulate matter (PM) emission limits, 

performance testing requirements, or 

monitoring requirements under this 

subpart (§§ 60.42c, 60.43c, 60.44c, 

60.45c, 60.46c, or 60.47c) during 

periods of combustion research, as 

defined in § 60.41c. 

(d) Any temporary change to an 

existing steam generating unit for the 

purpose of conducting combustion 

research is not considered a 

modification under § 60.14. 

(e) Heat recovery steam generators 

that are associated with combined cycle 

gas turbines and meet the applicability 

requirements of subpart GG or KKKK of 

this part are not subject to this subpart. 

This subpart will continue to apply to 

all other heat recovery steam generators 

that are capable of combusting more 

than or equal to 2.9 MW (10 MMBtu/hr) 

heat input of fossil fuel but less than or 

equal to 29 MW (100 MMBtu/hr) heat 

input of fossil fuel. If the heat recovery 

steam generator is subject to this 

subpart, only emissions resulting from 

combustion of fuels in the steam 

generating unit are subject to this 

subpart. (The gas turbine emissions are 

subject to subpart GG or KKKK, as 

applicable, of this part). 

(f) Any facility covered by subpart 

AAAA of this part is not covered by this 

subpart. 

(g) Any facility covered by an EPA 

approved State or Federal section 

111(d)/129 plan implementing subpart 

BBBB of this part is not covered by this 

subpart. 

§ 60.41c Definitions. 

As used in this subpart, all terms not 

defined herein shall have the meaning 

given them in the Clean Air Act and in 

subpart A of this part. 

Annual capacity factor means the 

ratio between the actual heat input to a 

steam generating unit from an 

individual fuel or combination of fuels 

during a period of 12 consecutive 

calendar months and the potential heat 

input to the steam generating unit from 

all fuels had the steam generating unit 

been operated for 8,760 hours during 

that 12-month period at the maximum 

design heat input capacity. In the case 

of steam generating units that are rented 

or leased, the actual heat input shall be 

determined based on the combined heat 

input from all operations of the affected 

facility during a period of 12 

consecutive calendar months. 

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), 

coal refuse, and petroleum coke. Coalderived synthetic fuels derived from 

coal for the purposes of creating useful 

heat, including but not limited to 

solvent refined coal, gasified coal, coaloil mixtures, and coal-water mixtures, 

are also included in this definition for 

the purposes of this subpart. 

Coal refuse means any by-product of 

coal mining or coal cleaning operations 

with an ash content greater than 50 

percent (by weight) and a heating value 

less than 13,900 kilojoules per kilogram 

(kJ/kg) (6,000 Btu per pound (Btu/lb) on 

a dry basis. 

Cogeneration steam generating unit 

means a steam generating unit that 

simultaneously produces both electrical 

(or mechanical) and thermal energy 

from the same primary energy source. 

Combined cycle system means a 

system in which a separate source (such 

as a stationary gas turbine, internal 

combustion engine, or kiln) provides 

exhaust gas to a steam generating unit. 

Combustion research means the 

experimental firing of any fuel or 

combination of fuels in a steam 

generating unit for the purpose of 

conducting research and development 

of more efficient combustion or more 

effective prevention or control of air 

pollutant emissions from combustion, 

provided that, during these periods of 

research and development, the heat 

generated is not used for any purpose 

other than preheating combustion air for 

use by that steam generating unit (i.e., 

the heat generated is released to the 

atmosphere without being used for 

space heating, process heating, driving 

pumps, preheating combustion air for 


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other units, generating electricity, or any 

other purpose). 

Conventional technology means wet 

flue gas desulfurization technology, dry 

flue gas desulfurization technology, 

atmospheric fluidized bed combustion 

technology, and oil 

hydrodesulfurization technology. 

Distillate oil means fuel oil that 

complies with the specifications for fuel 

oil numbers 1 or 2, as defined by the 

American Society for Testing and 

Materials in ASTM D396 (incorporated 

by reference, see § 60.17). 

Dry flue gas desulfurization 

technology means a SO2 control system 

that is located between the steam 

generating unit and the exhaust vent or 

stack, and that removes sulfur oxides 

from the combustion gases of the steam 

generating unit by contacting the 

combustion gases with an alkaline 

reagent and water, whether introduced 

separately or as a premixed slurry or 

solution and forming a dry powder 

material. This definition includes 

devices where the dry powder material 

is subsequently converted to another 

form. Alkaline reagents used in dry flue 

gas desulfurization systems include, but 

are not limited to, lime and sodium 

compounds. 

Duct burner means a device that 

combusts fuel and that is placed in the 

exhaust duct from another source (such 

as a stationary gas turbine, internal 

combustion engine, kiln, etc.) to allow 

the firing of additional fuel to heat the 

exhaust gases before the exhaust gases 

enter a steam generating unit. 

Emerging technology means any SO2

control system that is not defined as a 

conventional technology under this 

section, and for which the owner or 

operator of the affected facility has 

received approval from the 

Administrator to operate as an emerging 

technology under § 60.48c(a)(4). 

Federally enforceable means all 

limitations and conditions that are 

enforceable by the Administrator, 

including the requirements of 40 CFR 

parts 60 and 61, requirements within 

any applicable State implementation 

plan, and any permit requirements 

established under 40 CFR 52.21 or 

under 40 CFR 51.18 and 51.24. 

Fluidized bed combustion technology 

means a device wherein fuel is 

distributed onto a bed (or series of beds) 

of limestone aggregate (or other sorbent 

materials) for combustion; and these 

materials are forced upward in the 

device by the flow of combustion air 

and the gaseous products of 

combustion. Fluidized bed combustion 

technology includes, but is not limited 

to, bubbling bed units and circulating 

bed units. 

Fuel pretreatment means a process 

that removes a portion of the sulfur in 

a fuel before combustion of the fuel in 

a steam generating unit. 

Heat input means heat derived from 

combustion of fuel in a steam generating 

unit and does not include the heat 

derived from preheated combustion air, 

recirculated flue gases, or exhaust gases 

from other sources (such as stationary 

gas turbines, internal combustion 

engines, and kilns). 

Heat transfer medium means any 

material that is used to transfer heat 

from one point to another point. 

Maximum design heat input capacity 

means the ability of a steam generating 

unit to combust a stated maximum 

amount of fuel (or combination of fuels) 

on a steady state basis as determined by 

the physical design and characteristics 

of the steam generating unit. 

Natural gas means: (1) A naturally 

occurring mixture of hydrocarbon and 

nonhydrocarbon gases found in geologic 

formations beneath the earth’s surface, 

of which the principal constituent is 

methane; or (2) liquefied petroleum (LP) 

gas, as defined by the American Society 

for Testing and Materials in ASTM 

D1835 (incorporated by reference, see 

§ 60.17). 

Noncontinental area means the State 

of Hawaii, the Virgin Islands, Guam, 

American Samoa, the Commonwealth of 

Puerto Rico, or the Northern Mariana 

Islands. 

Oil means crude oil or petroleum, or 

a liquid fuel derived from crude oil or 

petroleum, including distillate oil and 

residual oil. 

Potential sulfur dioxide emission rate 

means the theoretical SO2 emissions 

(nanograms per joule (ng/J) or lb/ 

MMBtu heat input) that would result 

from combusting fuel in an uncleaned 

state and without using emission 

control systems. 

Process heater means a device that is 

primarily used to heat a material to 

initiate or promote a chemical reaction 

in which the material participates as a 

reactant or catalyst. 

Residual oil means crude oil, fuel oil 

that does not comply with the 

specifications under the definition of 

distillate oil, and all fuel oil numbers 4, 

5, and 6, as defined by the American 

Society for Testing and Materials in 

ASTM D396 (incorporated by reference, 

see § 60.17). 

Steam generating unit means a device 

that combusts any fuel and produces 

steam or heats water or any other heat 

transfer medium. This term includes 

any duct burner that combusts fuel and 

is part of a combined cycle system. This 

term does not include process heaters as 

defined in this subpart. 

Steam generating unit operating day 

means a 24-hour period between 12:00 

midnight and the following midnight 

during which any fuel is combusted at 

any time in the steam generating unit. 

It is not necessary for fuel to be 

combusted continuously for the entire 

24-hour period. 

Wet flue gas desulfurization 

technology means an SO2 control system 

that is located between the steam 

generating unit and the exhaust vent or 

stack, and that removes sulfur oxides 

from the combustion gases of the steam 

generating unit by contacting the 

combustion gases with an alkaline 

slurry or solution and forming a liquid 

material. This definition includes 

devices where the liquid material is 

subsequently converted to another form. 

Alkaline reagents used in wet flue gas 

desulfurization systems include, but are 

not limited to, lime, limestone, and 

sodium compounds. 

Wet scrubber system means any 

emission control device that mixes an 

aqueous stream or slurry with the 

exhaust gases from a steam generating 

unit to control emissions of PM or SO2. 

Wood means wood, wood residue, 

bark, or any derivative fuel or residue 

thereof, in any form, including but not 

limited to sawdust, sanderdust, wood 

chips, scraps, slabs, millings, shavings, 

and processed pellets made from wood 

or other forest residues. 

§ 60.42c Standard for sulfur dioxide (SO2). 

(a) Except as provided in paragraphs 

(b), (c), and (e) of this section, on and 

after the date on which the performance 

test is completed or required to be 

completed under § 60.8, whichever date 

comes first, the owner or operator of an 

affected facility that combusts only coal 

shall neither: cause to be discharged 

into the atmosphere from the affected 

facility any gases that contain SO2 in 

excess of 87 ng/J (0.20 lb/MMBtu) heat 

input or 10 percent (0.10) of the 

potential SO2 emission rate (90 percent 

reduction), nor cause to be discharged 

into the atmosphere from the affected 

facility any gases that contain SO2 in 

excess of 520 ng/J (1.2 lb/MMBtu) heat 

input. If coal is combusted with other 

fuels, the affected facility shall neither: 

cause to be discharged into the 

atmosphere from the affected facility 

any gases that contain SO2 in excess of 

87 ng/J (0.20 lb/MMBtu) heat input or 

10 percent (0.10) of the potential SO2

emission rate (90 percent reduction), 

nor cause to be discharged into the 

atmosphere from the affected facility 

any gases that contain SO2 in excess of 

the emission limit is determined 

pursuant to paragraph (e)(2) of this 

section. 


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(b) Except as provided in paragraphs 

(c) and (e) of this section, on and after 

the date on which the performance test 

is completed or required to be 

completed under § 60.8, whichever date 

comes first, the owner or operator of an 

affected facility that: 

(1) Combusts only coal refuse alone in 

a fluidized bed combustion steam 

generating unit shall neither: 

(i) Cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain SO2 in excess of 

87 ng/J (0.20 lb/MMBtu) heat input or 

20 percent (0.20) of the potential SO2

emission rate (80 percent reduction); 

nor 

(ii) Cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain SO2 in excess of 

SO2 in excess of 520 ng/J (1.2 lb/ 

MMBtu) heat input. If coal is fired with 

coal refuse, the affected facility subject 

to paragraph (a) of this section. If oil or 

any other fuel (except coal) is fired with 

coal refuse, the affected facility is 

subject to the 87 ng/J (0.20 lb/MMBtu) 

heat input SO2 emissions limit or the 90 

percent SO2 reduction requirement 

specified in paragraph (a) of this section 

and the emission limit is determined 

pursuant to paragraph (e)(2) of this 

section. 

(2) Combusts only coal and that uses 

an emerging technology for the control 

of SO2 emissions shall neither: 

(i) Cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain SO2 in excess of 

50 percent (0.50) of the potential SO2

emission rate (50 percent reduction); 

nor 

(ii) Cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain SO2 in excess of 

260 ng/J (0.60 lb/MMBtu) heat input. If 

coal is combusted with other fuels, the 

affected facility is subject to the 50 

percent SO2 reduction requirement 

specified in this paragraph and the 

emission limit determined pursuant to 

paragraph (e)(2) of this section. 

(c) 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, no owner or 

operator of an affected facility that 

combusts coal, alone or in combination 

with any other fuel, and is listed in 

paragraphs (c)(1), (2), (3), or (4) of this 

section shall cause to be discharged into 

the atmosphere from that affected 

facility any gases that contain SO2 in 

excess of the emission limit determined 

pursuant to paragraph (e)(2) of this 

section. Percent reduction requirements 

are not applicable to affected facilities 

under paragraphs (c)(1), (2), (3), or (4). 

(1) Affected facilities that have a heat 

input capacity of 22 MW (75 MMBtu/hr) 

or less. 

(2) Affected facilities that have an 

annual capacity for coal of 55 percent 

(0.55) or less and are subject to a 

federally enforceable requirement 

limiting operation of the affected facility 

to an annual capacity factor for coal of 

55 percent (0.55) or less. 

(3) Affected facilities located in a 

noncontinental area. 

(4) Affected facilities that combust 

coal in a duct burner as part of a 

combined cycle system where 30 

percent (0.30) or less of the heat 

entering the steam generating unit is 

from combustion of coal in the duct 

burner and 70 percent (0.70) or more of 

the heat entering the steam generating 

unit is from exhaust gases entering the 

duct burner. 

(d) 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, no owner or 

operator of an affected facility that 

combusts oil shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain SO2 in excess of 215 ng/J (0.50 

lb/MMBtu) heat input; or, as an 

alternative, no owner or operator of an 

affected facility that combusts oil shall 

combust oil in the affected facility that 

contains greater than 0.5 weight percent 

sulfur. The percent reduction 

requirements are not applicable to 

affected facilities under this paragraph. 

(e) 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, no owner or 

operator of an affected facility that 

combusts coal, oil, or coal and oil with 

any other fuel shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain SO2 in excess of the following: 

(1) The percent of potential SO2

emission rate or numerical SO2

emission rate required under paragraph 

(a) or (b)(2) of this section, as applicable, 

for any affected facility that 

(i) Combusts coal in combination with 

any other fuel; 

(ii) Has a heat input capacity greater 

than 22 MW (75 MMBtu/hr); and 

(iii) Has an annual capacity factor for 

coal greater than 55 percent (0.55); and 

(2) The emission limit determined 

according to the following formula for 

any affected facility that combusts coal, 

oil, or coal and oil with any other fuel: 

E

KH KH KH

HHH s

aa bb cc

abc

= ( ) + +

( ) + +

Where: 

Es = SO2 emission limit, expressed in ng/J or 

lb/MMBtu heat input; 

Ka = 520 ng/J (1.2 lb/MMBtu); 

Kb = 260 ng/J (0.60 lb/MMBtu); 

Kc = 215 ng/J (0.50 lb/MMBtu); 

Ha = Heat input from the combustion of coal, 

except coal combusted in an affected 

facility subject to paragraph (b)(2) of this 

section, in Joules (J) [MMBtu]; 

Hb = Heat input from the combustion of coal 

in an affected facility subject to 

paragraph (b)(2) of this section, in J 

(MMBtu); and 

Hc KaHb = Heat input from the combustion 

of oil, in J (MMBtu). 

(f) Reduction in the potential SO2

emission rate through fuel pretreatment 

is not credited toward the percent 

reduction requirement under paragraph 

(b)(2) of this section unless: 

(1) Fuel pretreatment results in a 50 

percent (0.50) or greater reduction in the 

potential SO2 emission rate; and 

(2) Emissions from the pretreated fuel 

(without either combustion or postcombustion SO2 control) are equal to or 

less than the emission limits specified 

under paragraph (b)(2) of this section. 

(g) Except as provided in paragraph 

(h) of this section, compliance with the 

percent reduction requirements, fuel oil 

sulfur limits, and emission limits of this 

section shall be determined on a 30-day 

rolling average basis. 

(h) For affected facilities listed under 

paragraphs (h)(1), (2), or (3) of this 

section, compliance with the emission 

limits or fuel oil sulfur limits under this 

section may be determined based on a 

certification from the fuel supplier, as 

described under § 60.48c(f), as 

applicable. 

(1) Distillate oil-fired affected 

facilities with heat input capacities 

between 2.9 and 29 MW (10 and 100 

MMBtu/hr). 

(2) Residual oil-fired affected facilities 

with heat input capacities between 2.9 

and 8.7 MW (10 and 30 MMBtu/hr). 

(3) Coal-fired facilities with heat input 

capacities between 2.9 and 8.7 MW (10 

and 30 MMBtu/hr). 

(i) The SO2 emission limits, fuel oil 

sulfur limits, and percent reduction 

requirements under this section apply at 

all times, including periods of startup, 

shutdown, and malfunction. 

(j) Only the heat input supplied to the 

affected facility from the combustion of 

coal and oil is counted under this 

section. No credit is provided for the 

heat input to the affected facility from 

wood or other fuels or for heat derived 

from exhaust gases from other sources, 

such as stationary gas turbines, internal 

combustion engines, and kilns. 


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32762 Federal Register / Vol. 72, No. 113 / Wednesday, June 13, 2007 / Rules and Regulations 

§ 60.43c Standard for particulate matter 

(PM). 

(a) 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, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification on or 

before February 28, 2005, that combusts 

coal or combusts mixtures of coal with 

other fuels and has a heat input capacity 

of 8.7 MW (30 MMBtu/hr) or greater, 

shall cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain PM in excess of 

the following emission limits: 

(1) 22 ng/J (0.051 lb/MMBtu) heat 

input if the affected facility combusts 

only coal, or combusts coal with other 

fuels and has an annual capacity factor 

for the other fuels of 10 percent (0.10) 

or less. 

(2) 43 ng/J (0.10 lb/MMBtu) heat input 

if the affected facility combusts coal 

with other fuels, has an annual capacity 

factor for the other fuels greater than 10 

percent (0.10), and is subject to a 

federally enforceable requirement 

limiting operation of the affected facility 

to an annual capacity factor greater than 

10 percent (0.10) for fuels other than 

coal. 

(b) 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, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification on or 

before February 28, 2005, that combusts 

wood or combusts mixtures of wood 

with other fuels (except coal) and has a 

heat input capacity of 8.7 MW (30 

MMBtu/hr) or greater, shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain PM in excess of the following 

emissions limits: 

(1) 43 ng/J (0.10 lb/MMBtu) heat input 

if the affected facility has an annual 

capacity factor for wood greater than 30 

percent (0.30); or 

(2) 130 ng/J (0.30 lb/MMBtu) heat 

input if the affected facility has an 

annual capacity factor for wood of 30 

percent (0.30) or less and is subject to 

a federally enforceable requirement 

limiting operation of the affected facility 

to an annual capacity factor for wood of 

30 percent (0.30) or less. 

(c) 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, no owner or 

operator of an affected facility that 

combusts coal, wood, or oil and has a 

heat input capacity of 8.7 MW (30 

MMBtu/hr) or greater shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

exhibit greater than 20 percent opacity 

(6-minute average), except for one 6- 

minute period per hour of not more than 

27 percent opacity. 

(d) The PM and opacity standards 

under this section apply at all times, 

except during periods of startup, 

shutdown, or malfunction. 

(e)(1) On and after the date on which 

the initial performance test is completed 

or is required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that commences construction, 

reconstruction, or modification after 

February 28, 2005, and that combusts 

coal, oil, wood, a mixture of these fuels, 

or a mixture of these fuels with any 

other fuels and has a heat input capacity 

of 8.7 MW (30 MMBtu/hr) or greater 

shall cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain PM in excess of 

13 ng/J (0.030 lb/MMBtu) heat input, 

except as provided in paragraphs (e)(2), 

(e)(3), and (e)(4) of this section. 

(2) As an alternative to meeting the 

requirements of paragraph (e)(1) of this 

section, the owner or operator of an 

affected facility for which modification 

commenced after February 28, 2005, 

may elect to meet the requirements of 

this paragraph. 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, no owner or operator of an affected 

facility that commences modification 

after February 28, 2005 shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain PM in excess of both: 

(i) 22 ng/J (0.051 lb/MMBtu) heat 

input derived from the combustion of 

coal, oil, wood, a mixture of these fuels, 

or a mixture of these fuels with any 

other fuels; and 

(ii) 0.2 percent of the combustion 

concentration (99.8 percent reduction) 

when combusting coal, oil, wood, a 

mixture of these fuels, or a mixture of 

these fuels with any other fuels. 

(3) On and after the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that commences modification after 

February 28, 2005, and that combusts 

over 30 percent wood (by heat input) on 

an annual basis and has a heat input 

capacity of 8.7 MW (30 MMBtu/hr) or 

greater shall cause to be discharged into 

the atmosphere from that affected 

facility any gases that contain PM in 

excess of 43 ng/J (0.10 lb/MMBtu) heat 

input. 

(4) On and after the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever date comes first, an 

owner or operator of an affected facility 

that commences construction, 

reconstruction, or modification after 

February 28, 2005, and that combusts 

only oil that contains no more than 0.50 

weight percent sulfur or a mixture of 

0.50 weight percent sulfur oil with other 

fuels not subject to a PM standard under 

§ 60.43c and not using a postcombustion technology (except a wet 

scrubber) to reduce PM or SO2

emissions is not subject to the PM limit 

in this section. 

§ 60.44c Compliance and performance test 

methods and procedures for sulfur dioxide. 

(a) Except as provided in paragraphs 

(g) and (h) of this section and § 60.8(b), 

performance tests required under § 60.8 

shall be conducted following the 

procedures specified in paragraphs (b), 

(c), (d), (e), and (f) of this section, as 

applicable. Section 60.8(f) does not 

apply to this section. The 30-day notice 

required in § 60.8(d) applies only to the 

initial performance test unless 

otherwise specified by the 

Administrator. 

(b) The initial performance test 

required under § 60.8 shall be 

conducted over 30 consecutive 

operating days of the steam generating 

unit. Compliance with the percent 

reduction requirements and SO2

emission limits under § 60.42c shall be 

determined using a 30-day average. The 

first operating day included in the 

initial performance test shall be 

scheduled within 30 days after 

achieving the maximum production rate 

at which the affect facility will be 

operated, but not later than 180 days 

after the initial startup of the facility. 

The steam generating unit load during 

the 30-day period does not have to be 

the maximum design heat input 

capacity, but must be representative of 

future operating conditions. 

(c) After the initial performance test 

required under paragraph (b) of this 

section and § 60.8, compliance with the 

percent reduction requirements and SO2

emission limits under § 60.42c is based 

on the average percent reduction and 

the average SO2 emission rates for 30 

consecutive steam generating unit 

operating days. A separate performance 

test is completed at the end of each 

steam generating unit operating day, 

and a new 30-day average percent 

reduction and SO2 emission rate are 

calculated to show compliance with the 

standard. 

(d) If only coal, only oil, or a mixture 

of coal and oil is combusted in an 


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Federal Register / Vol. 72, No. 113 / Wednesday, June 13, 2007 / Rules and Regulations 32763 

affected facility, the procedures in 

Method 19 of appendix A of this part 

are used to determine the hourly SO2

emission rate (Eho) and the 30-day 

average SO2 emission rate (Eao). The 

hourly averages used to compute the 30- 

day averages are obtained from the 

CEMS. Method 19 of appendix A of this 

part shall be used to calculate Eao when 

using daily fuel sampling or Method 6B 

of appendix A of this part. 

(e) If coal, oil, or coal and oil are 

combusted with other fuels: 

(1) An adjusted Eho (Ehoo) is used in 

Equation 19–19 of Method 19 of 

appendix A of this part to compute the 

adjusted Eao (Eaoo). The Ehoo is 

computed using the following formula: 

E o

EE X

X ho

ho w k

k

= − − ( ) 1

Where: 

Ehoo = Adjusted Eho, ng/J (lb/MMBtu); 

Eho = Hourly SO2 emission rate, ng/J (lb/ 

MMBtu); 

Ew = SO2 concentration in fuels other than 

coal and oil combusted in the affected 

facility, as determined by fuel sampling 

and analysis procedures in Method 9 of 

appendix A of this part, ng/J (lb/ 

MMBtu). The value Ew for each fuel lot 

is used for each hourly average during 

the time that the lot is being combusted. 

The owner or operator does not have to 

measure Ew if the owner or operator 

elects to assume Ew = 0. 

Xk = Fraction of the total heat input from fuel 

combustion derived from coal and oil, as 

determined by applicable procedures in 

Method 19 of appendix A of this part. 

(2) The owner or operator of an 

affected facility that qualifies under the 

provisions of § 60.42c(c) or (d) (where 

percent reduction is not required) does 

not have to measure the parameters Ew

or Xk if the owner or operator of the 

affected facility elects to measure 

emission rates of the coal or oil using 

the fuel sampling and analysis 

procedures under Method 19 of 

appendix A of this part. 

(f) Affected facilities subject to the 

percent reduction requirements under 

§ 60.42c(a) or (b) shall determine 

compliance with the SO2 emission 

limits under § 60.42c pursuant to 

paragraphs (d) or (e) of this section, and 

shall determine compliance with the 

percent reduction requirements using 

the following procedures: 

(1) If only coal is combusted, the 

percent of potential SO2 emission rate is 

computed using the following formula: 

%

% % PR R s

g f = − 



 



 − 



 



 100 1

100

1

100

Where: 

%Ps = Potential SO2 emission rate, in 

percent; 

%Rg = SO2 removal efficiency of the control 

device as determined by Method 19 of 

appendix A of this part, in percent; and 

%Rf = SO2 removal efficiency of fuel 

pretreatment as determined by Method 

19 of appendix A of this part, in percent. 

(2) If coal, oil, or coal and oil are 

combusted with other fuels, the same 

procedures required in paragraph (f)(1) 

of this section are used, except as 

provided for in the following: 

(i) To compute the %Ps, an adjusted 

%Rg (%Rgo) is computed from Eaoo from 

paragraph (e)(1) of this section and an 

adjusted average SO2 inlet rate (Eaio) 

using the following formula: 

%R o E

E g

ao

o

ai

o = − 



 



100 1 

Where: 

%Rgo = Adjusted %Rg, in percent; 

Eaoo = Adjusted Eao, ng/J (lb/MMBtu); and 

Eaio = Adjusted average SO2 inlet rate, ng/J 

(lb/MMBtu). 

(ii) To compute Eaio, an adjusted 

hourly SO2 inlet rate (Ehio) is used. The 

Ehio is computed using the following 

formula: 

E o

EE X

X hi

hi w k

k

= − − ( ) 1

Where: 

Ehio = Adjusted Ehi, ng/J (lb/MMBtu); 

Ehi = Hourly SO2 inlet rate, ng/J (lb/MMBtu); 

Ew = SO2 concentration in fuels other than 

coal and oil combusted in the affected 

facility, as determined by fuel sampling 

and analysis procedures in Method 19 of 

appendix A of this part, ng/J (lb/ 

MMBtu). The value Ew for each fuel lot 

is used for each hourly average during 

the time that the lot is being combusted. 

The owner or operator does not have to 

measure Ew if the owner or operator 

elects to assume Ew = 0; and 

Xk = Fraction of the total heat input from fuel 

combustion derived from coal and oil, as 

determined by applicable procedures in 

Method 19 of appendix A of this part. 

(g) For oil-fired affected facilities 

where the owner or operator seeks to 

demonstrate compliance with the fuel 

oil sulfur limits under § 60.42c based on 

shipment fuel sampling, the initial 

performance test shall consist of 

sampling and analyzing the oil in the 

initial tank of oil to be fired in the steam 

generating unit to demonstrate that the 

oil contains 0.5 weight percent sulfur or 

less. Thereafter, the owner or operator of 

the affected facility shall sample the oil 

in the fuel tank after each new shipment 

of oil is received, as described under 

§ 60.46c(d)(2). 

(h) For affected facilities subject to 

§ 60.42c(h)(1), (2), or (3) where the 

owner or operator seeks to demonstrate 

compliance with the SO2 standards 

based on fuel supplier certification, the 

performance test shall consist of the 

certification, the certification from the 

fuel supplier, as described under 

§ 60.48c(f), as applicable. 

(i) The owner or operator of an 

affected facility seeking to demonstrate 

compliance with the SO2 standards 

under § 60.42c(c)(2) shall demonstrate 

the maximum design heat input 

capacity of the steam generating unit by 

operating the steam generating unit at 

this capacity for 24 hours. This 

demonstration shall be made during the 

initial performance test, and a 

subsequent demonstration may be 

requested at any other time. If the 

demonstrated 24-hour average firing rate 

for the affected facility is less than the 

maximum design heat input capacity 

stated by the manufacturer of the 

affected facility, the demonstrated 24- 

hour average firing rate shall be used to 

determine the annual capacity factor for 

the affected facility; otherwise, the 

maximum design heat input capacity 

provided by the manufacturer shall be 

used. 

(j) The owner or operator of an 

affected facility shall use all valid SO2

emissions data in calculating %Ps and 

Eho under paragraphs (d), (e), or (f) of 

this section, as applicable, whether or 

not the minimum emissions data 

requirements under § 60.46c(f) are 

achieved. All valid emissions data, 

including valid data collected during 

periods of startup, shutdown, and 

malfunction, shall be used in 

calculating %Ps or Eho pursuant to 

paragraphs (d), (e), or (f) of this section, 

as applicable. 

§ 60.45c Compliance and performance test 

methods and procedures for particulate 

matter. 

(a) The owner or operator of an 

affected facility subject to the PM and/ 

or opacity standards under § 60.43c 

shall conduct an initial performance test 

as required under § 60.8, and shall 

conduct subsequent performance tests 

as requested by the Administrator, to 

determine compliance with the 

standards using the following 

procedures and reference methods, 

except as specified in paragraph (c) of 

this section. 

(1) Method 1 of appendix A of this 

part shall be used to select the sampling 

site and the number of traverse 

sampling points. 

(2) Method 3 of appendix A of this 

part shall be used for gas analysis when 

applying Method 5, 5B, or 17 of 

appendix A of this part. 


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32764 Federal Register / Vol. 72, No. 113 / Wednesday, June 13, 2007 / Rules and Regulations 

(3) Method 5, 5B, or 17 of appendix 

A of this part shall be used to measure 

the concentration of PM as follows: 

(i) Method 5 of appendix A of this 

part may be used only at affected 

facilities without wet scrubber systems. 

(ii) Method 17 of appendix A of this 

part may be used at affected facilities 

with or without wet scrubber systems 

provided the stack gas temperature does 

not exceed a temperature of 160 °C (320 

°F). The procedures of Sections 8.1 and 

11.1 of Method 5B of appendix A of this 

part may be used in Method 17 of 

appendix A of this part only if Method 

17 of appendix A of this part is used in 

conjunction with a wet scrubber system. 

Method 17 of appendix A of this part 

shall not be used in conjunction with a 

wet scrubber system if the effluent is 

saturated or laden with water droplets. 

(iii) Method 5B of appendix A of this 

part may be used in conjunction with a 

wet scrubber system. 

(4) The sampling time for each run 

shall be at least 120 minutes and the 

minimum sampling volume shall be 1.7 

dry standard cubic meters (dscm) [60 

dry standard cubic feet (dscf)] except 

that smaller sampling times or volumes 

may be approved by the Administrator 

when necessitated by process variables 

or other factors. 

(5) For Method 5 or 5B of appendix 

A of this part, the temperature of the 

sample gas in the probe and filter holder 

shall be monitored and maintained at 

160 ±14 °C (320±25 °F). 

(6) For determination of PM 

emissions, an oxygen (O2) or carbon 

dioxide (CO2) measurement shall be 

obtained simultaneously with each run 

of Method 5, 5B, or 17 of appendix A 

of this part by traversing the duct at the 

same sampling location. 

(7) For each run using Method 5, 5B, 

or 17 of appendix A of this part, the 

emission rates expressed in ng/J (lb/ 

MMBtu) heat input shall be determined 

using: 

(i) The O2 or CO2 measurements and 

PM measurements obtained under this 

section, (ii) The dry basis F factor, and 

(iii) The dry basis emission rate 

calculation procedure contained in 

Method 19 of appendix A of this part. 

(8) Method 9 of appendix A of this 

part (6-minute average of 24 

observations) shall be used for 

determining the opacity of stack 

emissions. 

(b) The owner or operator of an 

affected facility seeking to demonstrate 

compliance with the PM standards 

under § 60.43c(b)(2) shall demonstrate 

the maximum design heat input 

capacity of the steam generating unit by 

operating the steam generating unit at 

this capacity for 24 hours. This 

demonstration shall be made during the 

initial performance test, and a 

subsequent demonstration may be 

requested at any other time. If the 

demonstrated 24-hour average firing rate 

for the affected facility is less than the 

maximum design heat input capacity 

stated by the manufacturer of the 

affected facility, the demonstrated 24- 

hour average firing rate shall be used to 

determine the annual capacity factor for 

the affected facility; otherwise, the 

maximum design heat input capacity 

provided by the manufacturer shall be 

used. 

(c) In place of PM testing with EPA 

Reference Method 5, 5B, or 17 of 

appendix A of this part, an owner or 

operator may elect to install, calibrate, 

maintain, and operate a CEMS for 

monitoring PM emissions discharged to 

the atmosphere and record the output of 

the system. The owner or operator of an 

affected facility who elects to 

continuously monitor PM emissions 

instead of conducting performance 

testing using EPA Method 5, 5B, or 17 

of appendix A of this part shall install, 

calibrate, maintain, and operate a CEMS 

and shall comply with the requirements 

specified in paragraphs (c)(1) through 

(c)(13) of this section. 

(1) Notify the Administrator 1 month 

before starting use of the system. 

(2) Notify the Administrator 1 month 

before stopping use of the system. 

(3) The monitor shall be installed, 

evaluated, and operated in accordance 

with § 60.13 of subpart A of this part. 

(4) The initial performance evaluation 

shall be completed no later than 180 

days after the date of initial startup of 

the affected facility, as specified under 

§ 60.8 of subpart A of this part or within 

180 days of notification to the 

Administrator of use of CEMS if the 

owner or operator was previously 

determining compliance by Method 5, 

5B, or 17 of appendix A of this part 

performance tests, whichever is later. 

(5) The owner or operator of an 

affected facility shall conduct an initial 

performance test for PM emissions as 

required under § 60.8 of subpart A of 

this part. Compliance with the PM 

emission limit shall be determined by 

using the CEMS specified in paragraph 

(d) of this section to measure PM and 

calculating a 24-hour block arithmetic 

average emission concentration using 

EPA Reference Method 19 of appendix 

A of this part, section 4.1. 

(6) Compliance with the PM emission 

limit shall be determined based on the 

24-hour daily (block) average of the 

hourly arithmetic average emission 

concentrations using CEMS outlet data. 

(7) At a minimum, valid CEMS hourly 

averages shall be obtained as specified 

in paragraph (d)(7)(i) of this section for 

75 percent of the total operating hours 

per 30-day rolling average. 

(i) At least two data points per hour 

shall be used to calculate each 1-hour 

arithmetic average. 

(ii) [Reserved] 

(8) The 1-hour arithmetic averages 

required under paragraph (d)(7) of this 

section shall be expressed in ng/J or lb/ 

MMBtu heat input and shall be used to 

calculate the boiler operating day daily 

arithmetic average emission 

concentrations. The 1-hour arithmetic 

averages shall be calculated using the 

data points required under § 60.13(e)(2) 

of subpart A of this part. 

(9) All valid CEMS data shall be used 

in calculating average emission 

concentrations even if the minimum 

CEMS data requirements of paragraph 

(d)(7) of this section are not met. 

(10) The CEMS shall be operated 

according to Performance Specification 

11 in appendix B of this part. 

(11) During the correlation testing 

runs of the CEMS required by 

Performance Specification 11 in 

appendix B of this part, PM and O2 (or 

CO2) data shall be collected 

concurrently (or within a 30- to 60- 

minute period) by both the continuous 

emission monitors and the test methods 

specified in paragraph (d)(7)(i) of this 

section. 

(i) For PM, EPA Reference Method 5, 

5B, or 17 of appendix A of this part 

shall be used. 

(ii) For O2 (or CO2), EPA reference 

Method 3, 3A, or 3B of appendix A of 

this part, as applicable shall be used. 

(12) Quarterly accuracy 

determinations and daily calibration 

drift tests shall be performed in 

accordance with procedure 2 in 

appendix F of this part. Relative 

Response Audit’s must be performed 

annually and Response Correlation 

Audits must be performed every 3 years. 

(13) When PM emissions data are not 

obtained because of CEMS breakdowns, 

repairs, calibration checks, and zero and 

span adjustments, emissions data shall 

be obtained by using other monitoring 

systems as approved by the 

Administrator or EPA Reference Method 

19 of appendix A of this part to provide, 

as necessary, valid emissions data for a 

minimum of 75 percent of total 

operating hours on a 30-day rolling 

average. 

(d) The owner or operator of an 

affected facility seeking to demonstrate 

compliance under § 60.43c(e)(4) shall 

follow the applicable procedures under 

§ 60.48c(f). For residual oil-fired 

affected facilities, fuel supplier 

certifications are only allowed for 

facilities with heat input capacities 


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between 2.9 and 8.7 MW (10 to 30 

MMBtu/hr). 

§ 60.46c Emission monitoring for sulfur 

dioxide. 

(a) Except as provided in paragraphs 

(d) and (e) of this section, the owner or 

operator of an affected facility subject to 

the SO2 emission limits under § 60.42c 

shall install, calibrate, maintain, and 

operate a CEMS for measuring SO2

concentrations and either O2 or CO2

concentrations at the outlet of the SO2

control device (or the outlet of the steam 

generating unit if no SO2 control device 

is used), and shall record the output of 

the system. The owner or operator of an 

affected facility subject to the percent 

reduction requirements under § 60.42c 

shall measure SO2 concentrations and 

either O2 or CO2 concentrations at both 

the inlet and outlet of the SO2 control 

device. 

(b) The 1-hour average SO2 emission 

rates measured by a CEMS shall be 

expressed in ng/J or lb/MMBtu heat 

input and shall be used to calculate the 

average emission rates under § 60.42c. 

Each 1-hour average SO2 emission rate 

must be based on at least 30 minutes of 

operation, and shall be calculated using 

the data points required under 

§ 60.13(h)(2). Hourly SO2 emission rates 

are not calculated if the affected facility 

is operated less than 30 minutes in a 1- 

hour period and are not counted toward 

determination of a steam generating unit 

operating day. 

(c) The procedures under § 60.13 shall 

be followed for installation, evaluation, 

and operation of the CEMS. 

(1) All CEMS shall be operated in 

accordance with the applicable 

procedures under Performance 

Specifications 1, 2, and 3 of appendix B 

of this part. 

(2) Quarterly accuracy determinations 

and daily calibration drift tests shall be 

performed in accordance with 

Procedure 1 of appendix F of this part. 

(3) For affected facilities subject to the 

percent reduction requirements under 

§ 60.42c, the span value of the SO2

CEMS at the inlet to the SO2 control 

device shall be 125 percent of the 

maximum estimated hourly potential 

SO2 emission rate of the fuel combusted, 

and the span value of the SO2 CEMS at 

the outlet from the SO2 control device 

shall be 50 percent of the maximum 

estimated hourly potential SO2 emission 

rate of the fuel combusted. 

(4) For affected facilities that are not 

subject to the percent reduction 

requirements of § 60.42c, the span value 

of the SO2 CEMS at the outlet from the 

SO2 control device (or outlet of the 

steam generating unit if no SO2 control 

device is used) shall be 125 percent of 

the maximum estimated hourly 

potential SO2 emission rate of the fuel 

combusted. 

(d) As an alternative to operating a 

CEMS at the inlet to the SO2 control 

device (or outlet of the steam generating 

unit if no SO2 control device is used) as 

required under paragraph (a) of this 

section, an owner or operator may elect 

to determine the average SO2 emission 

rate by sampling the fuel prior to 

combustion. As an alternative to 

operating a CEMS at the outlet from the 

SO2 control device (or outlet of the 

steam generating unit if no SO2 control 

device is used) as required under 

paragraph (a) of this section, an owner 

or operator may elect to determine the 

average SO2 emission rate by using 

Method 6B of appendix A of this part. 

Fuel sampling shall be conducted 

pursuant to either paragraph (d)(1) or 

(d)(2) of this section. Method 6B of 

appendix A of this part shall be 

conducted pursuant to paragraph (d)(3) 

of this section. 

(1) For affected facilities combusting 

coal or oil, coal or oil samples shall be 

collected daily in an as-fired condition 

at the inlet to the steam generating unit 

and analyzed for sulfur content and heat 

content according the Method 19 of 

appendix A of this part. Method 19 of 

appendix A of this part provides 

procedures for converting these 

measurements into the format to be used 

in calculating the average SO2 input 

rate. 

(2) As an alternative fuel sampling 

procedure for affected facilities 

combusting oil, oil samples may be 

collected from the fuel tank for each 

steam generating unit immediately after 

the fuel tank is filled and before any oil 

is combusted. The owner or operator of 

the affected facility shall analyze the oil 

sample to determine the sulfur content 

of the oil. If a partially empty fuel tank 

is refilled, a new sample and analysis of 

the fuel in the tank would be required 

upon filling. Results of the fuel analysis 

taken after each new shipment of oil is 

received shall be used as the daily value 

when calculating the 30-day rolling 

average until the next shipment is 

received. If the fuel analysis shows that 

the sulfur content in the fuel tank is 

greater than 0.5 weight percent sulfur, 

the owner or operator shall ensure that 

the sulfur content of subsequent oil 

shipments is low enough to cause the 

30-day rolling average sulfur content to 

be 0.5 weight percent sulfur or less. 

(3) Method 6B of appendix A of this 

part may be used in lieu of CEMS to 

measure SO2 at the inlet or outlet of the 

SO2 control system. An initial 

stratification test is required to verify 

the adequacy of the Method 6B of 

appendix A of this part sampling 

location. The stratification test shall 

consist of three paired runs of a suitable 

SO2 and CO2 measurement train 

operated at the candidate location and 

a second similar train operated 

according to the procedures in § 3.2 and 

the applicable procedures in section 7 of 

Performance Specification 2 of 

appendix B of this part. Method 6B of 

appendix A of this part, Method 6A of 

appendix A of this part, or a 

combination of Methods 6 and 3 of 

appendix A of this part or Methods 6C 

and 3A of appendix A of this part are 

suitable measurement techniques. If 

Method 6B of appendix A of this part 

is used for the second train, sampling 

time and timer operation may be 

adjusted for the stratification test as long 

as an adequate sample volume is 

collected; however, both sampling trains 

are to be operated similarly. For the 

location to be adequate for Method 6B 

of appendix A of this part 24-hour tests, 

the mean of the absolute difference 

between the three paired runs must be 

less than 10 percent (0.10). 

(e) The monitoring requirements of 

paragraphs (a) and (d) of this section 

shall not apply to affected facilities 

subject to § 60.42c(h) (1), (2), or (3) 

where the owner or operator of the 

affected facility seeks to demonstrate 

compliance with the SO2 standards 

based on fuel supplier certification, as 

described under § 60.48c(f), as 

applicable. 

(f) The owner or operator of an 

affected facility operating a CEMS 

pursuant to paragraph (a) of this section, 

or conducting as-fired fuel sampling 

pursuant to paragraph (d)(1) of this 

section, shall obtain emission data for at 

least 75 percent of the operating hours 

in at least 22 out of 30 successive steam 

generating unit operating days. If this 

minimum data requirement is not met 

with a single monitoring system, the 

owner or operator of the affected facility 

shall supplement the emission data with 

data collected with other monitoring 

systems as approved by the 

Administrator. 

§ 60.47c Emission monitoring for 

particulate matter. 

(a) Except as provided in paragraphs 

(c), (d), (e), and (f) of this section, the 

owner or operator of an affected facility 

combusting coal, oil, or wood that is 

subject to the opacity standards under 

§ 60.43c shall install, calibrate, 

maintain, and operate a COMS for 

measuring the opacity of the emissions 

discharged to the atmosphere and 

record the output of the system. 

(b) All COMS for measuring opacity 

shall be operated in accordance with the 


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32766 Federal Register / Vol. 72, No. 113 / Wednesday, June 13, 2007 / Rules and Regulations 

applicable procedures under 

Performance Specification 1 of 

appendix B of this part. The span value 

of the opacity COMS shall be between 

60 and 80 percent. 

(c) Affected facilities that burn only 

distillate oil that contains no more than 

0.5 weight percent sulfur and/or liquid 

or gaseous fuels with potential sulfur 

dioxide emission rates of 26 ng/J (0.06 

lb/MMBtu) heat input or less and that 

do not use a post-combustion 

technology to reduce SO2 or PM 

emissions are not required to operate a 

CEMS for measuring opacity if they 

follow the applicable procedures under 

§ 60.48c(f). 

(d) Owners or operators complying 

with the PM emission limit by using a 

PM CEMS monitor instead of 

monitoring opacity must calibrate, 

maintain, and operate a CEMS, and 

record the output of the system, for PM 

emissions discharged to the atmosphere 

as specified in § 60.45c(d). The CEMS 

specified in paragraph § 60.45c(d) shall 

be operated and data recorded during all 

periods of operation of the affected 

facility except for CEMS breakdowns 

and repairs. Data is recorded during 

calibration checks, and zero and span 

adjustments. 

(e) An affected facility that does not 

use post-combustion technology (except 

a wet scrubber) for reducing PM, SO2, or 

carbon monoxide (CO) emissions, burns 

only gaseous fuels or fuel oils that 

contain less than or equal to 0.5 weight 

percent sulfur, and is operated such that 

emissions of CO to the atmosphere from 

the affected facility are maintained at 

levels less than or equal to 0.15 lb/ 

MMBtu on a boiler operating day 

average basis is not required to operate 

a COMS for measuring opacity. Owners 

and operators of affected facilities 

electing to comply with this paragraph 

must demonstrate compliance according 

to the procedures specified in 

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

section. 

(1) You must monitor CO emissions 

using a CEMS according to the 

procedures specified in paragraphs 

(e)(1)(i) through (iv) of this section. 

(i) The CO CEMS must be installed, 

certified, maintained, and operated 

according to the provisions in 

§ 60.58b(i)(3) of subpart Eb of this part. 

(ii) Each 1-hour CO emissions average 

is calculated using the data points 

generated by the CO CEMS expressed in 

parts per million by volume corrected to 

3 percent oxygen (dry basis). 

(iii) At a minimum, valid 1-hour CO 

emissions averages must be obtained for 

at least 90 percent of the operating 

hours on a 30-day rolling average basis. 

At least two data points per hour must 

be used to calculate each 1-hour 

average. 

(iv) Quarterly accuracy 

determinations and daily calibration 

drift tests for the CO CEMS must be 

performed in accordance with 

procedure 1 in appendix F of this part. 

(2) You must calculate the 1-hour 

average CO emissions levels for each 

steam generating unit operating day by 

multiplying the average hourly CO 

output concentration measured by the 

CO CEMS times the corresponding 

average hourly flue gas flow rate and 

divided by the corresponding average 

hourly heat input to the affected source. 

The 24-hour average CO emission level 

is determined by calculating the 

arithmetic average of the hourly CO 

emission levels computed for each 

steam generating unit operating day. 

(3) You must evaluate the preceding 

24-hour average CO emission level each 

steam generating unit operating day 

excluding periods of affected source 

startup, shutdown, or malfunction. If 

the 24-hour average CO emission level 

is greater than 0.15 lb/MMBtu, you must 

initiate investigation of the relevant 

equipment and control systems within 

24 hours of the first discovery of the 

high emission incident and, take the 

appropriate corrective action as soon as 

practicable to adjust control settings or 

repair equipment to reduce the 24-hour 

average CO emission level to 0.15 lb/ 

MMBtu or less. 

(4) You must record the CO 

measurements and calculations 

performed according to paragraph (e) of 

this section and any corrective actions 

taken. The record of corrective action 

taken must include the date and time 

during which the 24-hour average CO 

emission level was greater than 0.15 lb/ 

MMBtu, and the date, time, and 

description of the corrective action. 

(f) An affected facility that burns only 

gaseous fuels or fuel oils that contain 

less than or equal to 0.5 weight percent 

sulfur and operates according to a 

written site-specific monitoring plan 

approved by the appropriate delegated 

permitting authority is not required to 

operate a COMS for measuring opacity. 

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. 

§ 60.48c Reporting and recordkeeping 

requirements. 

(a) The owner or operator of each 

affected facility shall submit notification 

of the date of construction or 

reconstruction and actual startup, as 

provided by § 60.7 of this part. This 

notification shall include: 

(1) The design heat input capacity of 

the affected facility and identification of 

fuels to be combusted in the affected 

facility. 

(2) If applicable, a copy of any 

federally enforceable requirement that 

limits the annual capacity factor for any 

fuel or mixture of fuels under § 60.42c, 

or § 60.43c. 

(3) The annual capacity factor at 

which the owner or operator anticipates 

operating the affected facility based on 

all fuels fired and based on each 

individual fuel fired. 

(4) Notification if an emerging 

technology will be used for controlling 

SO2 emissions. The Administrator will 

examine the description of the control 

device and will determine whether the 

technology qualifies as an emerging 

technology. In making this 

determination, the Administrator may 

require the owner or operator of the 

affected facility to submit additional 

information concerning the control 

device. The affected facility is subject to 

the provisions of § 60.42c(a) or (b)(1), 

unless and until this determination is 

made by the Administrator. 

(b) The owner or operator of each 

affected facility subject to the SO2

emission limits of § 60.42c, or the PM or 

opacity limits of § 60.43c, shall submit 

to the Administrator the performance 

test data from the initial and any 

subsequent performance tests and, if 

applicable, the performance evaluation 

of the CEMS and/or COMS using the 

applicable performance specifications in 

appendix B of this part. 

(c) The owner or operator of each 

coal-fired, oil-fired, or wood-fired 

affected facility subject to the opacity 

limits under § 60.43c(c) shall submit 

excess emission reports for any excess 

emissions from the affected facility that 

occur during the reporting period. 

(d) The owner or operator of each 

affected facility subject to the SO2

emission limits, fuel oil sulfur limits, or 

percent reduction requirements under 

§ 60.42c shall submit reports to the 

Administrator. 

(e) The owner or operator of each 

affected facility subject to the SO2

emission limits, fuel oil sulfur limits, or 

percent reduction requirements under 

§ 60.42c shall keep records and submit 

reports as required under paragraph (d) 

of this section, including the following 

information, as applicable. 

(1) Calendar dates covered in the 

reporting period. 

(2) Each 30-day average SO2 emission 

rate (ng/J or lb/MMBtu), or 30-day 

average sulfur content (weight percent), 

calculated during the reporting period, 

ending with the last 30-day period; 

reasons for any noncompliance with the 


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Federal Register / Vol. 72, No. 113 / Wednesday, June 13, 2007 / Rules and Regulations 32767 

emission standards; and a description of 

corrective actions taken. 

(3) Each 30-day average percent of 

potential SO2 emission rate calculated 

during the reporting period, ending with 

the last 30-day period; reasons for any 

noncompliance with the emission 

standards; and a description of the 

corrective actions taken. 

(4) Identification of any steam 

generating unit operating days for which 

SO2 or diluent (O2 or CO2) data have not 

been obtained by an approved method 

for at least 75 percent of the operating 

hours; justification for not obtaining 

sufficient data; and a description of 

corrective actions taken. 

(5) Identification of any times when 

emissions data have been excluded from 

the calculation of average emission 

rates; justification for excluding data; 

and a description of corrective actions 

taken if data have been excluded for 

periods other than those during which 

coal or oil were not combusted in the 

steam generating unit. 

(6) Identification of the F factor used 

in calculations, method of 

determination, and type of fuel 

combusted. 

(7) Identification of whether averages 

have been obtained based on CEMS 

rather than manual sampling methods. 

(8) If a CEMS is used, identification of 

any times when the pollutant 

concentration exceeded the full span of 

the CEMS. 

(9) If a CEMS is used, description of 

any modifications to the CEMS that 

could affect the ability of the CEMS to 

comply with Performance Specifications 

2 or 3 of appendix B of this part. 

(10) If a CEMS is used, results of daily 

CEMS drift tests and quarterly accuracy 

assessments as required under appendix 

F, Procedure 1 of this part. 

(11) If fuel supplier certification is 

used to demonstrate compliance, 

records of fuel supplier certification is 

used to demonstrate compliance, 

records of fuel supplier certification as 

described under paragraph (f)(1), (2), (3), 

or (4) of this section, as applicable. In 

addition to records of fuel supplier 

certifications, the report shall include a 

certified statement signed by the owner 

or operator of the affected facility that 

the records of fuel supplier 

certifications submitted represent all of 

the fuel combusted during the reporting 

period. 

(f) Fuel supplier certification shall 

include the following information: 

(1) For distillate oil: 

(i) The name of the oil supplier; 

(ii) A statement from the oil supplier 

that the oil complies with the 

specifications under the definition of 

distillate oil in § 60.41c; and 

(iii) The sulfur content of the oil. 

(2) For residual oil: 

(i) The name of the oil supplier; 

(ii) The location of the oil when the 

sample was drawn for analysis to 

determine the sulfur content of the oil, 

specifically including whether the oil 

was sampled as delivered to the affected 

facility, or whether the sample was 

drawn from oil in storage at the oil 

supplier’s or oil refiner’s facility, or 

other location; 

(iii) The sulfur content of the oil from 

which the shipment came (or of the 

shipment itself); and 

(iv) The method used to determine the 

sulfur content of the oil. 

(3) For coal: 

(i) The name of the coal supplier; 

(ii) The location of the coal when the 

sample was collected for analysis to 

determine the properties of the coal, 

specifically including whether the coal 

was sampled as delivered to the affected 

facility or whether the sample was 

collected from coal in storage at the 

mine, at a coal preparation plant, at a 

coal supplier’s facility, or at another 

location. The certification shall include 

the name of the coal mine (and coal 

seam), coal storage facility, or coal 

preparation plant (where the sample 

was collected); 

(iii) The results of the analysis of the 

coal from which the shipment came (or 

of the shipment itself) including the 

sulfur content, moisture content, ash 

content, and heat content; and 

(iv) The methods used to determine 

the properties of the coal. 

(4) For other fuels: 

(i) The name of the supplier of the 

fuel; 

(ii) The potential sulfur emissions rate 

of the fuel in ng/J heat input; and 

(iii) The method used to determine 

the potential sulfur emissions rate of the 

fuel. 

(g)(1) Except as provided under 

paragraphs (g)(2) and (g)(3) of this 

section, the owner or operator of each 

affected facility shall record and 

maintain records of the amount of each 

fuel combusted during each operating 

day. 

(2) As an alternative to meeting the 

requirements of paragraph (g)(1) of this 

section, the owner or operator of an 

affected facility that combusts only 

natural gas, wood, fuels using fuel 

certification in § 60.48c(f) to 

demonstrate compliance with the SO2

standard, fuels not subject to an 

emissions standard (excluding opacity), 

or a mixture of these fuels may elect to 

record and maintain records of the 

amount of each fuel combusted during 

each calendar month. 

(3) As an alternative to meeting the 

requirements of paragraph (g)(1) of this 

section, the owner or operator of an 

affected facility or multiple affected 

facilities located on a contiguous 

property unit where the only fuels 

combusted in any steam generating unit 

(including steam generating units not 

subject to this subpart) at that property 

are natural gas, wood, distillate oil 

meeting the most current requirements 

in § 60.42C to use fuel certification to 

demonstrate compliance with the SO2

standard, and/or fuels, excluding coal 

and residual oil, not subject to an 

emissions standard (excluding opacity) 

may elect to record and maintain 

records of the total amount of each 

steam generating unit fuel delivered to 

that property during each calendar 

month. 

(h) The owner or operator of each 

affected facility subject to a federally 

enforceable requirement limiting the 

annual capacity factor for any fuel or 

mixture of fuels under § 60.42c or 

§ 60.43c shall calculate the annual 

capacity factor individually for each 

fuel combusted. The annual capacity 

factor is determined on a 12-month 

rolling average basis with a new annual 

capacity factor calculated at the end of 

the calendar month. 

(i) All records required under this 

section shall be maintained by the 

owner or operator of the affected facility 

for a period of two years following the 

date of such record. 

(j) The reporting period for the reports 

required under this subpart is each sixmonth period. All reports shall be 

submitted to the Administrator and 

shall be postmarked by the 30th day 

following the end of the reporting 

period. 

Appendix B—[Amended] 

■ 7. Appendix B to part 60 is amended 

by revising section 8.3.1 in Performance 

Specification 2, to read as follows: 

Appendix B to Part 60—Performance 

Specifications 

* * * * * 

Performance Specification 2—Specifications 

and Test Procedures for SO2 and NOX

Continuous Emission Monitoring Systems in 

Stationary Sources 

* * * * * 

8.3.1 CD Test Period. While the affected 

facility is operating, determine the magnitude 

of the CD once each day (at 24-hour intervals) 

for 7 consecutive calendar days according to 

the procedure given in Sections 8.3.2 through 

8.3.4. Alternatively, the CD test may be 

conducted over 7 consecutive unit operating 

days. 

* * * * * 


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Appendix F—[Amended] 

■ 8. Procedure 1 in Appendix F to part 

60 is amended by: 

■ a. Revising the first sentence of 

section 5.1.1; and 

■ b. Revising section 5.1.4. 

The revisions read as follows: 

Appendix F to Part 60—Quality 

Assurance Procedures 

* * * * * 

5.1.1 Relative Accuracy Test Audit 

(RATA). The RATA must be conducted at 

least once every four calendar quarters, 

except as otherwise noted in section 5.1.4 of 

this appendix. 

* * * * * 

5.1.4 Other Alternative Audits. Other 

alternative audit procedures may be used as 

approved by the Administrator for three of 

four calendar quarters. One RATA is required 

at least every four calendar quarters, except 

in the case where the affected facility is offline (does not operate) in the fourth calendar 

quarter since the quarter of the previous 

RATA. In that case, the RATA shall be 

performed in the quarter in which the unit 

recommences operation. Also, cylinder gas 

audits are not be required for calendar 

quarters in which the affected facility does 

not operate. 

* * * * * 

[FR Doc. E7–7673 Filed 6–12–07; 8:45 am] 

BILLING CODE 6560–50–P 


sroberts on PROD1PC70 with RULES