5072 Federal Register / Vol. 74, No. 17 / Wednesday, January 28, 2009 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[EPA–HQ–OAR–2005–0031; FRL–8748–2] 

RIN 2060–AO61 

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 rule. 

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, eliminate the opacity standard 

for facilities with a particulate matter 

(PM) limit of 0.030 lb/million British 

thermal units (MMBtu) or less that 

choose to voluntarily install and use PM 

continuous emission monitors (CEMS) 

to demonstrate compliance with that 

limit, and to correct technical and 

editorial errors. 

DATES: This final rule is effective on 

January 28, 2009. The incorporation by 

reference of certain publications listed 

in this final rule is approved by the 

Director of the Federal Register as of 

January 28, 2009. 

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 http:// 

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 Response to 

Public Comments 

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. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. General Information 

A. Does this action apply to me? 

The regulated categories and entities 

potentially affected by this final action 

include, but are not limited to, the 

following: 

Category NAICS Code1 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 60.4c. 

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 


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applicability criteria in § 60.40, § 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 

EPA regional representative as listed in 

§ 63.13 of subpart A (General 

Provisions) of title 40 of the Code of 

Federal Regulations. 

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 March 30, 2009. 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 of the amendments to 

the new source performance standards 

for steam generating units that EPA 

promulgated on June 13, 2007 (72 FR 

32710) filed by the Coke Oven 

Environmental Task Force, EPA 

proposed revised amendments to 

address issues for which the petitioners 

requested reconsideration (see docket 

entry EPA–HQ–OAR–2005–0031–0276). 

EPA also proposed certain other 

unrelated amendments it felt were 

appropriate. In sum, EPA proposed on 

June 12, 2008 (73 FR 33642) to amend 

subparts D, Da, Db, and Dc of 40 CFR 

part 60 to clarify the intent for applying 

and implementing specific rule 

requirements, provide additional 

compliance alternatives, and to correct 

unintentional technical omissions and 

editorial errors. 

A 45-day comment period (June 12, 

2008 to July 28, 2008) 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. We received comments on the 

proposed amendments from 11 

commenters during the comment 

period. 

III. Final Amendments and Response to 

Public Comments 

We are amending subparts D, Da, Db, 

and Dc of 40 CFR part 60 to add 

compliance alternatives for owners/ 

operators of certain affected sources, to 

eliminate the opacity standard for 

certain facilities voluntarily using PM 

CEMS, and to correct technical and 

editorial errors. These amendments 

address issues raised by the Coke Oven 

Environmental Task Force, including an 

alternate sulfur dioxide (SO2) limit 

during SO2 control system maintenance 

and allowing the use of parametric 

monitoring of nitrogen oxide (NOX) 

emissions for owners and operators of 

coke oven gas-fired (COG) steam 

generating units. In addition, we are 

specifying the opacity monitoring 

requirements for owners and operators 

of all affected facilities that are subject 

to an opacity limit, including owner and 

operators of COG-fired steam generating 

units, but exempt from the continuous 

opacity monitoring system (COMS) 

requirement. This action promulgates 

the amended regulatory language as 

proposed, except for those significant 

provisions identified below. 

We are also finalizing several 

clarifications to correct technical and 

editorial errors and to amend the 

monitoring requirements for owners and 

operators of affected facilities that elect 

to install particulate matter continuous 

emission monitoring systems (PM 

CEMS). Owners and operators of 

affected facilities that install a PM 

CEMS will be exempt from the opacity 

standard as long as they are complying 

with a federally enforceable permit 

limiting PM emissions to 0.030 pounds 

per million British thermal units or less. 

In addition, owner and operators of 

affected facilities that elect to install PM 

CEMS will be required to measure and 

report emissions of condensable PM. 

Minor revisions to the proposed 

regulatory language were also 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 either as 

a result of comments we received or 

based on our own subsequent review of 

the text. One change revises 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. Another change clarifies the fact 

that not all combined cycle facilities 

that burn solid derived fuels are subject 

to the subpart. 

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. A summary of 

selected public comments and our 

responses is as follows. 

Comment: Several commenters 

generally support the exemption of 

affected facilities using PM CEMS from 

the opacity standard. However, the 

commenters requested that EPA exempt 

those affected facilities opting to use PM 

CEMS from the opacity standard 

without imposing conditions for 

additional condensable PM or opacity 

tests. The commenters stated the EPA’s 

proposed method for measuring 

condensable PM (Method 202) is flawed 

and significantly overstates the amount 

of condensable PM, and noted that 

Method 202 itself condenses gaseous 

emissions that would not be condensing 

in the flue gas. They also noted that 

further improvements of Method 202 

must be made before it is required as the 

method to measure condensable PM. 

Response: The opacity standard and 

all opacity monitoring requirements 

have been eliminated for owner/ 

operators of affected facilities 

complying with a federally enforceable 

PM limit of 0.030 lb/MMBtu or less who 

voluntarily elect to use a PM CEMS to 

demonstrate continuous compliance 

with the PM limit. The contribution of 

filterable PM to opacity at these 

emission levels is generally negligible, 

and sources with mass limits at this 

level or less will operate with little or 

no visible emissions (i.e. less than 5 

percent opacity). As a result, EPA 

believes that an opacity standard is no 

longer necessary for these sources since 

the PM mass emission rate standard is 

substantially tighter than the opacity 

standard and the mass of PM emissions 

will be continually monitored. 

We concluded, however, that it is 

only appropriate to eliminate the 

opacity standard and associated opacity 

monitoring for owners/operators of 

facilities complying with a PM limit of 


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0.030 lb/MMBtu or less. At this 

emission rate, the presence of visible 

emissions may indicate that the PM 

control device is not operating properly. 

This amended NSPS does not require 

any corrective action in such a case as 

long as the PM CEMS is complying with 

all applicable federal requirements. 

However, PM CEMS readings cannot be 

verified as readily as other CEMS, and 

since recalibration requires PM 

performance tests, baseline opacity 

readings can be a valuable secondary 

check on control device performance 

and PM emissions. The local permitting 

authority does have the discretion to 

require an investigation to determine 

the cause of the visible emissions. The 

presence of such emissions is not, 

however, necessarily evidence of a 

violation of the PM standard. In 

situations where the owner/operator of 

a facility has documented visible 

emissions during the initial or 

subsequent PM CEMS calibration testing 

or documented trends in PM CEMS 

readings that correlate to the visible 

emissions, the relative amount of visible 

emissions can still be used by the local 

permitting authority as a secondary 

check that both the PM control device 

and PM CEMS are operating properly. 

While these facilities will not be 

required to install continuous opacity 

monitoring systems (COMS), if a facility 

decided to or is required by the 

permitting authority to install a COMS, 

the data would be useful as a secondary 

check on PM emissions and proper 

operation of the PM control device and 

to verify that the PM CEMS is operating 

properly. Owners/operators of affected 

facilities with a PM limit greater than 

0.030 lb/MMBtu that elect to install PM 

CEMS may have some visible emissions, 

will still be subject to an opacity limit, 

and will be required to either use a 

COMS or perform periodic visual 

inspections to comply with the opacity 

standard. 

In addition, we have concluded it is 

appropriate to require condensable PM 

testing for owners/operators of affected 

facilities that elect to use PM CEMS to 

determine the contribution of 

condensable PM to total PM emissions. 

We will use this data to determine if the 

condensable PM emissions from steam 

generating units have a significant 

health and/or environmental impact and 

whether condensable PM should be 

included in future amendments to the 

PM standard. By early 2009, we intend 

to propose amendments to Method 202 

that will address the concerns about 

artifact measurement. Since the rule 

will not be finalized until early in 2010, 

we are delaying the requirement to 

perform condensable PM testing until 

July 1, 2010 or until Method 202 is 

revised to minimize artifact 

measurement, whichever is later. 

Comment: Several commenters 

oppose increasing the Method 9 

monitoring frequency. The commenters 

stated that increasing the frequency 

from annually to a weekly, monthly, or 

quarterly basis without identifying any 

particular issue of concern that might 

occur on a weekly, monthly, or 

quarterly basis is arbitrary, unnecessary, 

overly burdensome, and would provide 

little environmental benefit. In addition, 

one commenter supports the use of 

Method 22 as an alternative to Method 

9 for those sources that are expected to 

have no significant visible emissions. 

However, three 1-hour Method 22 

observations would actually take 

significantly longer than 3 hours. Under 

Method 22, observers are instructed not 

to continuously view emissions for 

more than 15–20 minutes at a time, and 

that breaks of 5–10 minutes should be 

taken between each observation. 

Following these criteria, each 1-hour 

observation would take at least one and 

a half hours. Finally, one commenter 

requested that EPA allow for owners/ 

operators of affected facilities that 

comply with subpart D, Da, Db, or Dc, 

by the use of a fabric filter, the 

alternative of installing and operating 

triboelectric bag leak detectors as an 

alternative to using a COMS. 

Response: We have concluded that 

the appropriate approach is to base the 

frequency of visible emissions 

monitoring on the level of visible 

emissions detected during the most 

recent observation. Owners/operators of 

facilities that elect to not use a COMS 

to demonstrate compliance with the 

opacity limit will conduct at least an 

initial Method 9 performance test. The 

frequency of the required subsequent 

Method 9 testing is based on the results 

of the highest 6-minute opacity 

observed during the most recent 

performance test. Owners/operators of 

affected facilities where the maximum 

6-minute opacity reading is greater than 

10 percent will be required to conduct 

monthly Method 9 performance testing; 

owners/operators of affected facilities 

where the maximum 6-minute opacity 

reading is between 5 percent and 10 

percent will be required to conduct 

quarterly Method 9 performance testing; 

owners/operators of affected facilities 

with some visible emissions but where 

the maximum 6-minute opacity reading 

is 5 percent or less will be required to 

conduct semi-annual Method 9 

performance testing; and owners/ 

operators of affected facilities with no 

visible emissions will only be required 

to conduct an annual Method 9 

performance test. 

As an alternative, owners/operators of 

affected facilities where maximum 6- 

minute opacity readings from the most 

recent Method 9 performance test is less 

than 10 percent may elect to use either 

Method 22 or the digital opacity 

monitoring system in lieu of subsequent 

Method 9 performance testing. The 

proposed amendments required a total 

of 3 hours of observation annually, but 

did not specify when or for how long 

those observations would be done. We 

have concluded it is appropriate to 

decrease the length of each observation 

to a minimum of 10 minutes, but to 

increase the frequency to daily 

observations. This approach both 

minimizes the burden of this option 

while increasing protection to the 

environment, as observations will be 

performed throughout the year. If an 

owner/operator of an affected facility 

observes visible emissions in excess of 

5 percent during any observation and is 

unable to take corrective action, they 

will be required to either conduct a 

Method 9 performance test with the 

previously specified frequency or to 

install a COMS. To maintain 

consistency in the operation of the 

digital opacity monitoring system, the 

EPA Administrator will approve opacity 

monitoring plans for owners/operators 

that elect to use the digital opacity 

monitoring system to detect the 

presence of visible emissions. 

Finally, we have concluded it is 

appropriate to allow owners/operators 

of affected facilities subject to subparts 

Da, Db, and Dc, and who install, 

maintain, and operate a bag leak 

detection system, the option to use 

periodic visual inspections of plume 

opacity as an alternative to monitoring 

opacity with a COMS. Modern 

baghouses often operate with no visible 

emissions, and a bag leak detection 

system will allow owners/operators to 

identify potential problems with the 

control device and repair the problems 

prior to increases in opacity. 

Comment: Several commenters 

oppose the proposed requirement to 

electronically submit performance 

evaluation test date to EPA’s WebFIRE 

database. One commenter stated that 

EPA has not: (1) Provided any rationale 

for requiring the data to be reported and 

entered electronically; (2) provided any 

information on the proposed reporting 

format or mechanism to allow interested 

parties to understand what sort of 

burden this requirement would impose 

and whether the requirement is more or 

less burdensome than other forms of 

reporting; or (3) provided any 

mechanism for sources to confirm the 


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authenticity of data submitted to this 

Web site for their facility. Furthermore, 

before EPA can impose any new 

reporting requirement, EPA must 

comply with the requirements of the 

Paperwork Reduction Act and also 

address whether the submission meets 

the requirements of the Cross-Media 

Electronic Reporting Rule (CROMERR), 

which is codified at 40 CFR part 3. 

Another commenter stated that any 

reporting should not be required of 

sources until the WebFIRE is fully 

operational. A formal regulation is not 

the proper venue to ‘‘troubleshoot’’ 

communications with an external 

database for the regulated community. 

Response: EPA does not expect 

WebFIRE and the associated Electronic 

Reporting Tool (ERT) to be operational 

until early 2011, and we are delaying 

the requirement until July 1, 2011. We 

do not expect electronic submittal of 

performance test information to have 

any significant costs or impacts to 

industry (because we are not requiring 

additional testing or software and 

source testing companies already 

compile these data electronically), and 

since submission of data directly to EPA 

is only a requirement for facilities that 

voluntary elect to use PM CEMS to 

demonstrate compliance with the PM 

limit, the ICR does not need to be 

amended. In addition, as an alternate to 

using the ERT we are allowing owner/ 

operators to mail the test report directly 

to EPA. Finally, we fully expect the ERT 

to be compliant with CROMERR before 

reporting is required in 2011. 

Comment: Two commenters requested 

that EPA reconsider the Agency’s 

decision to include direct contact water 

heaters in the definition of ‘‘steam 

generating unit’’ used for determining 

applicability of the requirements under 

subparts Db and Dc because it is 

contrary to previous EPA applicability 

determinations, and it is confusing to 

include water heaters in a regulation for 

steam generating units. 

Response: The definition of steam 

generating unit includes direct contact 

water heaters and as such, these units 

meet the applicability of subpart Dc. 

However, we recognize that two sourcespecific letters exempt individual direct 

contact water heaters from the 

applicability of subpart Dc of 40 CFR 

part 60, and owners/operators of the 

units in question reasonably relied on 

these determinations and have not been 

complying with subpart Dc to date. We 

do not intend to reverse these source 

specific determinations or to require 

retroactive reporting for any owner/ 

operators of similar facilities that relied 

on these determinations and have not 

been maintaining the proper records, 

but we are clarifying and confirming 

that direct contact water heaters have 

always been subject to subpart Dc, and 

records shall be maintained from June 

12, 2008 onward, consistent with the 

definition of steam generating unit. 

V. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under Executive Order 12866 (58 FR 

51735, October 4, 1993), this action is a 

‘‘significant regulatory action’’ because 

it may raise novel legal or policy issues 

arising out of legal mandates, the 

President’s priorities, or the principles 

set forth in the Executive Order. 

Accordingly, EPA submitted this action 

to the Office of Management and Budget 

(OMB) for review under Executive 

Order 12866 and any changes made in 

response to OMB recommendations 

have been documented in the docket for 

this action. 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden. The final 

rule results in no changes to the 

information collection requirements of 

the existing standards of performance 

and will have no impact on the 

information collection estimate of 

projected cost and hour burden made 

and approved by the OMB during the 

development of the existing standards of 

performance. Therefore, the information 

collection requests have not been 

amended. However, OMB previously 

approved the information collection 

requirements contained in the existing 

regulations (subparts Da, Db, and Dc of 

40 CFR part 60) under the provisions of 

the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq., and has assigned OMB 

control numbers 2060–0023 for subpart 

Da of 40 CFR part 60, 2060–0072 for 

subpart Db of 40 CFR part 60, and 2060– 

0202 for subpart Dc of 40 CFR part 60. 

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. 

In determining whether a rule has a 

significant economic impact on a 

substantial number of small entities, the 

impact of concern is any significant 

adverse economic impact on small 

entities, since the primary purpose of 

the regulatory flexibility analyses is to 

identify and address regulatory 

alternatives ‘‘which minimize any 

significant economic impact of the rule 

on small entities.’’ 5 U.S.C. 603 and 604. 

Thus, an agency may certify that a rule 

will not have a significant economic 

impact on a substantial number of small 

entities if the rule relieves regulatory 

burden, or otherwise has a positive 

economic effect on all of the small 

entities subject to the rule. 

EPA is minimizing the opacity 

monitoring requirements for owner/ 

operators of affected facilities subject to 

an opacity standard but exempt from the 

COMS requirement. We have therefore 

concluded that this final rule will 

relieve regulatory burden for all affected 

small entities. 

D. Unfunded Mandates Reform Act 

This rule does not change the overall 

cost of the rule and therefore does not 

contain a Federal mandate that may 

result in expenditures of $100 million or 

more for State, local, and trial 

governments, in the aggregate, or the 

private sector in any 1 year. Thus, this 

final rule is not subject to the 

requirements of sections 202 or 205 of 

UMRA. 

This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. This 

rule modifies previously established 

requirements and does not impose any 

new obligations or enforceable duties on 

any small governments. 


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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.’’ 

This final rule does not have 

federalism implications. It will not have 

substantial direct effects on the States, 

on the relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. This action 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 this rule. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). While utility steam generating 

units are located on tribal lands, EPA is 

not aware of any that are owned by 

tribal governments. Thus, Executive 

Order 13175 does not apply to this 

action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

EPA interprets Executive Order 13045 

(62 FR 19885, April 23, 1997) as 

applying to those regulatory actions that 

concern health or safety risks, such that 

the analysis required under section 5– 

501 of the Executive Order has the 

potential to influence the regulation. 

This action is not subject to Executive 

Order 13045 because it is based solely 

on technology performance. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not a ‘‘significant 

energy action’’ as defined in Executive 

Order 13211 (66 FR 28355, May 22, 

2001) because it is not likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy. We have 

concluded that this final rule is not 

likely to have any adverse energy effects 

because it generally only clarifies our 

intent and corrects errors in the existing 

rule. 

I. National Technology Transfer 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

104–113 (15 U.S.C. 272 note) directs 

EPA to use voluntary consensus 

standards (VCS) in its regulatory 

activities unless to do so would be 

inconsistent with applicable law or 

otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, and 

business practices) that are developed or 

adopted by voluntary consensus 

standards bodies. NTTAA directs EPA 

to provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. 

This final rule involves technical 

standards. EPA has decided to use 

ASTM D975–08a, ‘‘Standard 

Specification for Diesel Fuel Oils,’’ for 

defining diesel fuel oil. This standard is 

available from the American Society for 

Testing and Materials (ASTM), 100 Barr 

Harbor Drive, Post Office Box C700, 

West Conshohocken, PA 19428–2959. 

EPA has also decided to use EPA 

Method 202 (40 CFR part 51, appendix 

M). The Agency has not found any 

alternative methods. The search and 

review results are in the docket for this 

regulation. 

Under 40 CFR 60.13(i) of the NSPS 

General Provisions, a source may apply 

to EPA for permission to use alternative 

test methods or alternative monitoring 

requirements in place of any required 

testing methods, performance 

specifications, or procedures in the final 

rule and amendments. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994) establishes Federal 

executive policy on environmental 

justice. Its main provision directs 

Federal agencies, to the greatest extent 

practical and permitted by law, to make 

environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA has determined that this final 

rule will not have disproportionately 

high and adverse human health or 

environmental effects on minority or 

low-income populations because it does 

not affect the level of protection 

provided to human health or the 

environment. This action does not 

change any emission limits and, 

therefore, does not affect the level of 

protection provided to human health or 

the environment. 

H. 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). This 

final rule will be effective on January 

28, 2009. 

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: November 26, 2008. 

Stephen L. Johnson, 

Administrator. 

Editorial Note: This document was 

received in the Office of the Federal Register 

on Thursday, January 8, 2009. 

■ For the reasons stated in the preamble, 

title 40, chapter I, part 60 of the Code 

of 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 60.17 is amended by 

redesignating paragraphs (a)(17) through 

(a)(92) as paragraphs (a)(18) through 

(a)(93) and by adding new paragraph 

(a)(17) to read as follows: 


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§ 60.17 Incorporations by Reference. 

* * * * * 

(a) * * * 

(17) ASTM D975–08a, Standard 

Specification for Diesel Fuel Oils, IBR 

approved for §§ 60.41b of subpart Db of 

this part and 60.41c of subpart Dc of this 

part. 

* * * * * 

Subpart D—[Amended] 

■ 3. Section 60.42 is amended by adding 

paragraph (c) to read as follows: 

§ 60.42 Standard for particulate matter 

(PM). 

* * * * * 

(c) As an alternate to meeting the 

requirements of paragraph (a) of this 

section, an owner or operator that elects 

to install, calibrate, maintain, and 

operate a continuous emissions 

monitoring systems (CEMS) for 

measuring PM emissions can petition 

the Administrator (in writing) to comply 

with § 60.42Da(a) 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 

§ 60.43Da(a) of subpart Da of this part. 

■ 4. Section 60.43 is amended by 

revising paragraph (d) to read as 

follows: 

* * * * * 

§ 60.43 Standard for sulfur dioxide (SO2). 

(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)(4) 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)(4) 

of subpart Db of this part, as applicable 

to the affected source. 

■ 5. Section 60.45 is amended to read as 

follows: 

■ a. By revising paragraph (a); 

■ b. By revising paragraphs (b)(1) and 

(b)(6)(i)(C) and adding paragraph (b)(7); 

■ c. By revising paragraphs (g)(2), (g)(3), 

and (g)(4); and 

■ d. By adding paragraph (h). 

§ 60.45 Emissions and fuel monitoring. 

(a) Each owner or operator shall 

install, calibrate, maintain, and operate 

continuous opacity monitoring system 

(COMS) for measuring opacity and a 

CEMS for measuring SO2 emissions, 

NOX emissions, and either oxygen (O2) 

or carbon dioxide (CO2) except as 

provided in paragraph (b) of this 

section. 

(b) * * * 

(1) For a fossil-fuel-fired steam 

generator that burns only gaseous or 

liquid fossil fuel (excluding residual oil) 

with potential SO2 emissions rates of 26 

ng/J (0.060 lb/MMBtu) or less and that 

does not use post-combustion 

technology to reduce emissions of SO2

or PM, CEMS for measuring the opacity 

of emissions and SO2 emissions are not 

required if the owner or operator 

monitors SO2 emissions by fuel 

sampling and analysis or fuel receipts. 

* * * * * 

(6) * * * 

(i) * * * 

(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. 

The 1-hour averages are calculated 

using the data points required in 

§ 60.13(h)(2). 

* * * * * 

(7) The owner or operator of an 

affected facility subject to an opacity 

standard under § 60.42 and that elects to 

not install a COMS because the affected 

facility burns only fuels as specified 

under paragraph (b)(1) of this section, 

monitors PM emissions as specified 

under paragraph (b)(5) of this section, or 

monitors CO emissions as specified 

under paragraph (b)(6) of this section 

shall conduct a performance test using 

Method 9 of appendix A–4 of this part 

and the procedures in § 60.11 to 

demonstrate compliance with the 

applicable limit in § 60.42 and shall 

comply with either paragraphs (b)(7)(i), 

(b)(7)(ii), or (b)(7)(iii) of this section. If 

during the initial 60 minutes of 

observation all 6-minute averages are 

less than 10 percent and all individual 

15-second observations are less than or 

equal to 20 percent, the observation 

period may be reduced from 3 hours to 

60 minutes. 

(i) Except as provided in paragraph 

(b)(7)(ii) or (b)(7)(iii) of this section, the 

owner or operator shall conduct 

subsequent Method 9 of appendix A–4 

of this part performance tests using the 

procedures in paragraph (b)(7) of this 

section according to the applicable 

schedule in paragraphs (b)(7)(i)(A) 

through (b)(7)(i)(D) of this section, as 

determined by the most recent Method 

9 of appendix A–4 of this part 

performance test results. 

(A) If no visible emissions are 

observed, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 12 

calendar months from the date that the 

most recent performance test was 

conducted; 

(B) If visible emissions are observed 

but the maximum 6-minute average 

opacity is less than or equal to 5 

percent, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 6 

calendar months from the date that the 

most recent performance test was 

conducted; 

(C) If the maximum 6-minute average 

opacity is greater than 5 percent but less 

than or equal to 10 percent, a 

subsequent Method 9 of appendix A–4 

of this part performance test must be 

completed within 3 calendar months 

from the date that the most recent 

performance test was conducted; or 

(D) If the maximum 6-minute average 

opacity is greater than 10 percent, a 

subsequent Method 9 of appendix A–4 

of this part performance test must be 

completed within 30 calendar days from 

the date that the most recent 

performance test was conducted. 

(ii) If the maximum 6-minute opacity 

is less than 10 percent during the most 

recent Method 9 of appendix A–4 of this 

part performance test, the owner or 

operator may, as an alternative to 

performing subsequent Method 9 of 

appendix A–4 of this part performance 

test, elect to perform subsequent 

monitoring using Method 22 of 

appendix A–7 of this part according to 

the procedures specified in paragraphs 

(b)(7)(ii)(A) and (B) of this section. 

(A) The owner or operator shall 

conduct 10 minute observations (during 

normal operation) each operating day 

the affected facility fires fuel for which 

an opacity standard is applicable using 

Method 22 of appendix A–7 of this part 

and demonstrate that the sum of the 

occurrences of any visible emissions is 

not in excess of 5 percent of the 

observation period (i.e., 30 seconds per 

10 minute period). If the sum of the 

occurrence of any visible emissions is 

greater than 30 seconds during the 

initial 10 minute observation, 

immediately conduct a 30 minute 

observation. If the sum of the 

occurrence of visible emissions is 

greater than 5 percent of the observation 

period (i.e., 90 seconds per 30 minute 

period) the owner or operator shall 

either document and adjust the 

operation of the facility and 

demonstrate within 24 hours that the 

sum of the occurrence of visible 

emissions is equal to or less than 5 

percent during a 30 minute observation 

(i.e., 90 seconds) or conduct a new 

Method 9 of appendix A–4 of this part 

performance test using the procedures 


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in paragraph (b)(7) of this section within 

30 calendar days according to the 

requirements in § 60.46(b)(3). 

(B) If no visible emissions are 

observed for 30 operating days during 

which an opacity standard is applicable, 

observations can be reduced to once 

every 7 operating days during which an 

opacity standard is applicable. If any 

visible emissions are observed, daily 

observations shall be resumed. 

(iii) If the maximum 6-minute opacity 

is less than 10 percent during the most 

recent Method 9 of appendix A–4 of this 

part performance test, the owner or 

operator may, as an alternative to 

performing subsequent Method 9 of 

appendix A–4 performance tests, elect 

to perform subsequent monitoring using 

a digital opacity compliance system 

according to a site-specific monitoring 

plan approved by the Administrator. 

The observations shall be similar, but 

not necessarily identical, to the 

requirements in paragraph (b)(7)(ii) of 

this section. For reference purposes in 

preparing the monitoring plan, see 

OAQPS ‘‘Determination of Visible 

Emission Opacity from Stationary 

Sources Using Computer-Based 

Photographic Analysis Systems.’’ This 

document is available from the U.S. 

Environmental Protection Agency (U.S. 

EPA); Office of Air Quality and 

Planning Standards; Sector Policies and 

Programs Division; Measurement Policy 

Group (D243–02), Research Triangle 

Park, NC 27711. This document is also 

available on the Technology Transfer 

Network (TTN) under Emission 

Measurement Center Preliminary 

Methods. 

* * * * * 

(g) * * * 

(2) Sulfur dioxide. Excess emissions 

for affected facilities are defined as: 

(i) For affected facilities electing not 

to comply with § 60.43(d), any threehour 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 in § 60.43; or 

(ii) For affected facilities electing to 

comply with § 60.43(d), 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 

in § 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 

or §§ 60.45b and 60.47b of subpart Db of 

this part, as applicable. 

(3) Nitrogen oxides. Excess emissions 

for affected facilities using a CEMS for 

measuring NOX are defined as: 

(i) For affected facilities electing not 

to comply with § 60.44(e), any threehour period during which the average 

emissions (arithmetic average of three 

contiguous one-hour periods) exceed 

the applicable standards in § 60.44; or 

(ii) For affected facilities electing to 

comply with § 60.44(e), 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 

in § 60.44. 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 in § 60.42. Affected facilities 

using PM CEMS must follow the most 

current applicable compliance and 

monitoring provisions in §§ 60.48Da 

and 60.49Da of subpart Da of this part. 

(h) The owner or operator of an 

affected facility subject to the opacity 

limits in § 60.42 that elects to monitor 

emissions according to the requirements 

in § 60.45(b)(7) shall maintain records 

according to the requirements specified 

in paragraphs (h)(1) through (3) of this 

section, as applicable to the visible 

emissions monitoring method used. 

(1) For each performance test 

conducted using Method 9 of appendix 

A–4 of this part, the owner or operator 

shall keep the records including the 

information specified in paragraphs 

(h)(1)(i) through (iii) of this section. 

(i) Dates and time intervals of all 

opacity observation periods; 

(ii) Name, affiliation, and copy of 

current visible emission reading 

certification for each visible emission 

observer participating in the 

performance test; and 

(iii) Copies of all visible emission 

observer opacity field data sheets; 

(2) For each performance test 

conducted using Method 22 of appendix 

A–4 of this part, the owner or operator 

shall keep the records including the 

information specified in paragraphs 

(h)(2)(i) through (iv) of this section. 

(i) Dates and time intervals of all 

visible emissions observation periods; 

(ii) Name and affiliation for each 

visible emission observer participating 

in the performance test; 

(iii) Copies of all visible emission 

observer opacity field data sheets; and 

(iv) Documentation of any 

adjustments made and the time the 

adjustments were completed to the 

affected facility operation by the owner 

or operator to demonstrate compliance 

with the applicable monitoring 

requirements. 

(3) For each digital opacity 

compliance system, the owner or 

operator shall maintain records and 

submit reports according to the 

requirements specified in the sitespecific monitoring plan approved by 

the Administrator. 

■ 6. Section 60.46 is amended by 

revising paragraph (d)(2) to read as 

follows: 

§ 60.46 Test methods and procedures. 

* * * * * 

(d) * * * 

(2) For Method 5 or 5B of appendix 

A–3 of this part, Method 17 of appendix 

A–6 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 160 °C (320 °F). The 

procedures of sections 8.1 and 11.1 of 

Method 5B of appendix A–3 of this part 

may be used with Method 17 of 

appendix A–6 of this part only if it is 

used after wet FGD systems. Method 17 

of appendix A–6 of this part shall not 

be used after wet FGD systems if the 

effluent gas is saturated or laden with 

water droplets. 

* * * * * 

Subpart Da—[Amended] 

■ 7. Section 60.40Da is amended by 

revising paragraphs (a) and (b), and 

adding paragraph (e) to read as follows: 

§ 60.40Da Applicability and designation of 

affected facility. 

(a) Except as specified in paragraph 

(e) of this section, 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. 

(b) An IGCC electric utility steam 

generating unit (both the stationary 

combustion turbine and any associated 

duct burners) is subject to this part and 

is not subject to subpart GG or KKKK of 

this part if both of the conditions 

specified in paragraphs (b)(1) and (2) of 

this section are met. 


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(1) The IGCC electric utility steam 

generating unit 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 IGCC electric utility steam 

generating unit commenced 

construction, modification, or 

reconstruction after February 28, 2005. 

* * * * * 

(e) Applicability of the requirement of 

this subpart to an electric utility 

combined cycle gas turbine other than 

an IGCC electric utility steam generating 

unit is as specified in paragraphs (e)(1) 

and (2) of this section. 

(1) Heat recovery steam generators 

used with duct burners and associated 

with an electric utility combined cycle 

gas turbine that are capable of 

combusting more than 73 MW (250 

MMBtu/hr) heat input of fossil fuel are 

subject to this subpart except in cases 

when the heat recovery steam generator 

meets the applicability requirements 

and is subject to subpart KKKK of this 

part. 

(2) For heat recovery steam generators 

use with duct burners subject to this 

subpart, only emissions resulting from 

the combustion of fuels in the steam 

generating unit (i.e. duct burners) are 

subject to the standards under this 

subpart. (The emissions resulting from 

the combustion of fuels in the stationary 

combustion turbine engine are subject to 

subpart GG or KKK, as applicable, of 

this part). 

■ 8. Section 60.41Da is amended by 

revising the definitions of ‘‘Gross 

output,’’ ‘‘Integrated gasification 

combined cycle electric utility steam 

generating unit or IGCC electric utility 

steam generating unit,’’ ‘‘Natural gas,’’ 

and ‘‘Petroleum’’ to read as follows: 

§ 60.41Da Definitions. 

* * * * * 

Gross output means the gross useful 

work performed by the steam generated 

and, for an IGCC electric utility steam 

generating unit, the work performed by 

the 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 or to enhance the performance of 

the unit (i.e., steam delivered to an 

industrial process). 

* * * * * 

Integrated gasification combined 

cycle electric utility steam generating 

unit or IGCC electric utility steam 

generating unit means an electric utility 

combined cycle gas turbine that is 

designed to burn fuels containing 50 

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

of natural gas. No solid fuel is directly 

burned in the unit during operation. 

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 dry standard cubic 

meter (910 and 1,150 Btu per dry 

standard cubic foot). 

* * * * * 

Petroleum means crude oil or a fuel 

derived from crude oil, including, but 

not limited to, distillate oil, and residual 

oil. 

* * * * * 

■ 9. Section 60.42Da is amended by 

revising paragraph (b) to read as follows: 

§ 60.42Da Standard for particulate matter 

(PM). 

* * * * * 

(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. Owners and operators of an 

affected facility that elect to install, 

calibrate, maintain, and operate a 

continuous emissions monitoring 

system (CEMS) for measuring PM 

emissions according to the requirements 

of this subpart are exempt from the 

opacity standard specified in this 

paragraph b. 

* * * * * 

■ 10. Section 60.48Da is amended to 

read as follows: 

■ a. By revising paragraph (g)(3); 

■ b. By revising the first sentence of 

paragraph (j)(2); 

■ c. By revising paragraph (n); 

■ d. By revising paragraph (o) 

introductory text; 

■ e. By revising paragraph (o)(1); 

■ f. By revising paragraph (o)(2)(ii); 

■ g. By revising the last sentence of 

paragraph (o)(2)(iii); 

■ h. By revising paragraphs (o)(2)(iv) 

and (o)(2)(vi); 

■ i. By revising paragraphs (o)(3)(i) and 

(o)(3)(ii); 

■ j. By revising the first sentence of 

paragraph (o)(3)(iii); 

■ k. By revising the last sentence of 

paragraph (o)(3)(v); 

■ l. By revising paragraph (o)(4)(i)(E); 

■ m. By revising the first sentence of 

paragraph (o)(4)(ii); 

■ n. By revising paragraphs (o)(4)(ii)(F), 

(o)(4)(v) and (o)(4)(5); 

■ o. By revising paragraph (p) 

introductory text and (p)(2); and 

■ p. By adding paragraph (q). 

§ 60.48Da Compliance provisions. 

* * * * * 

(g) * * * 

(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, all of the 

valid hourly emission rates of the 

operating day(s) not meeting the 

minimum 18 hours valid data daily 

average requirement are averaged with 

all of the valid hourly emission rates of 

the next boiler operating day with 18 

hours or more of valid PM CEMS data 

to determine compliance. 

* * * * * 

(j) * * * 

(2) The owner or operator of an 

affected duct burner may elect to 

determine compliance by using the 

CEMS specified under § 60.49Da for 

measuring NOX and oxygen (O2) (or 

carbon dioxide (CO2)) and meet the 

requirements of § 60.49Da. * * * 

* * * * * 

(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) or 

§ 60.49Da(m)), and divided by the 

average hourly gross energy output 

(measured according to the provisions 

of § 60.49Da(k)). Compliance with the 


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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. 

(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 following the date the 

previous performance test was required 

to be conducted. You must conduct 

each performance test according to the 

requirements in § 60.8 using the test 

methods and procedures in § 60.50Da. 

The owner or operator of an affected 

facility that has not operated for 60 

consecutive calendar days prior to the 

date that the subsequent performance 

test would have been required had the 

unit been operating is not required to 

perform the subsequent performance 

test until 30 calendar days after the next 

boiler operating day. Requests for 

additional 30 day extensions shall be 

granted by the relevant air division or 

office director of the appropriate 

Regional Office of the U.S. EPA. 

(2) * * * 

(ii) You must comply with the quality 

assurance requirements in paragraphs 

(o)(2)(ii)(A) through (E) of this section. 

* * * * * 

(iii) * * * If your opacity baseline 

level 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 facility 

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. 

In cases when a wet scrubber is used in 

combination with another PM control 

device that serves as the primary PM 

control device, the wet scrubber must be 

maintained and operated. 

* * * * * 

(vi) If the measured 24-hour average 

opacity for your affected facility remains 

at a level greater than the opacity 

baseline level after 7 boiler operating 

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 measured 24-hour average 

opacity was first determined to exceed 

the baseline opacity level unless a 

waiver is granted by the permitting 

authority. 

(3) * * * 

(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 wet scrubber must be 

maintained and operated. 

(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 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 facility startup, shutdown, or 

malfunction. * * * 

* * * * * 

(v) * * * This new performance test 

must be conducted within 60 calendar 

days of the date that the model 

parameter was first determined to 

exceed its baseline level unless a waiver 

is granted by the permitting authority. 

(4) * * * 

(i) * * * 

(E) Following initial adjustment, you 

must not adjust the averaging period, 

alarm set point, or alarm delay time 

without approval from the permitting 

authority except as provided in 

paragraph (d)(1)(vi) of this section. 

* * * * * 

(ii) You must develop and submit to 

the permitting authority for approval a 

site-specific monitoring plan for each 

bag leak detection system. * * * 

* * * * * 

(F) Corrective action procedures as 

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

section. In approving the site-specific 

monitoring plan, the 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 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. 

* * * * * 

(v) If after any period 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 calendar days of 

the date that the alarm rate was first 

determined to exceed 5 percent limit 

unless a waiver is granted by the 

permitting authority. 

(5) An owner or operator of a 

modified affected facility electing to 

meet the emission limitations in 

§ 60.42Da(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 


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or operator may elect to install, 

evaluate, 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. 

* * * * * 

(2) Each CEMS shall be installed, 

evaluated, operated, and maintained 

according to the requirements in 

§ 60.49Da(v). 

* * * * * 

(q) Compliance provisions for sources 

subject to § 60.42Da(b). An owner or 

operator of an affected facility subject to 

the opacity standard in § 60.42Da(b) 

shall monitor the opacity of emissions 

discharged from the affected facility to 

the atmosphere according to the 

requirements in § 60.49Da(a), as 

applicable to the affected facility. 

■ 11. Section 60.49Da is amended to 

read as follows: 

■ a. By revising paragraph (a); 

■ b. By revising paragraphs (b)(4) 

introductory text and (b)(4)(iii); 

■ c. By revising paragraph (d); 

■ d. By revising paragraph (i)(3); 

■ e. By revising paragraph (k) 

introductory text; 

■ f. By revising paragraph (t); 

■ g. By revising paragraph (u); 

■ h. By revising paragraphs (v) 

introductory text and (v)(2), and adding 

paragraph (v)(4); and 

■ j. By adding paragraph (w) 

introductory text; 

■ k. By revising paragraphs (w)(1) and 

(w)(2). 

§ 60.49Da Emission monitoring. 

(a) An owner or operator of an 

affected facility subject to the opacity 

standard in § 60.42Da(b) shall monitor 

the opacity of emissions discharged 

from the affected facility to the 

atmosphere according to the applicable 

requirements in paragraphs (a)(1) 

through (3) of this section. 

(1) Except as provided for in 

paragraph (a)(2) of this section, the 

owner or operator of an affected facility, 

shall install, calibrate, maintain, and 

operate a COMS, 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). 

(2) As an alternative to the monitoring 

requirements in paragraph (a)(1) of this 

section, an owner or operator of an 

affected facility that meets the 

conditions in either paragraph (a)(2)(i), 

(ii), or (iii) of this section may elect to 

monitor opacity as specified in 

paragraph (a)(3) of this section. 

(i) The affected facility uses a fabric 

filter (baghouse) to meet the standards 

in § 60.42Da and a bag leak detection 

system is installed and operated 

according to the requirements in 

paragraphs § 60.48Da(o)(4)(i) through 

(v); 

(ii) The affected facility burns only 

gaseous or liquid fuels (excluding 

residual oil) with potential SO2

emissions rates of 26 ng/J (0.060 lb/ 

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

emissions of SO2 or PM; or 

(iii) The affected facility meets all of 

the conditions specified in paragraphs 

(a)(2)(iii)(A) through (C) of this section. 

(A) No post-combustion technology 

(except a wet scrubber) is used for 

reducing PM, SO2, or carbon monoxide 

(CO) emissions; 

(B) Only natural gas, gaseous fuels, or 

fuel oils that contain less than or equal 

to 0.30 weight percent sulfur are 

burned; and 

(C) Emissions of CO discharged to the 

atmosphere are maintained at levels less 

than or equal to 1.4 lb/MWh on a boiler 

operating day average basis as 

demonstrated by the use of a CEMS 

measuring CO emissions according to 

the procedures specified in paragraph 

(u) of this section. 

(3) The owner or operators of an 

affected facility that meets the 

conditions in paragraph (a)(2) of this 

section may, as an alternative to COMS, 

elect to monitor visible emissions using 

the applicable procedures specified in 

paragraphs (a)(3)(i) through (iv) of this 

section. 

(i) The owner or operator shall 

conduct a performance test using 

Method 9 of appendix A–4 of this part 

and the procedures in § 60.11. If during 

the initial 60 minutes of the observation 

all the 6-minute averages are less than 

10 percent and all the individual 15- 

second observations are less than or 

equal to 20 percent, then the 

observation period may be reduced from 

3 hours to 60 minutes. 

(ii) Except as provided in paragraph 

(a)(3)(iii) or (iv) of this section, the 

owner or operator shall conduct 

subsequent Method 9 of appendix A–4 

of this part performance tests using the 

procedures in paragraph (a)(3)(i) of this 

section according to the applicable 

schedule in paragraphs (a)(3)(ii)(A) 

through (a)(3)(ii)(D) of this section, as 

determined by the most recent Method 

9 of appendix A–4 of this part 

performance test results. 

(A) If no visible emissions are 

observed, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 12 

calendar months from the date that the 

most recent performance test was 

conducted; 

(B) If visible emissions are observed 

but the maximum 6-minute average 

opacity is less than or equal to 5 

percent, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 6 

calendar months from the date that the 

most recent performance test was 

conducted; 

(C) If the maximum 6-minute average 

opacity is greater than 5 percent but less 

than or equal to 10 percent, a 

subsequent Method 9 of appendix A–4 

of this part performance test must be 

completed within 3 calendar months 

from the date that the most recent 

performance test was conducted; or 

(D) If the maximum 6-minute average 

opacity is greater than 10 percent, a 

subsequent Method 9 of appendix A–4 

of this part performance test must be 

completed within 30 calendar days from 

the date that the most recent 

performance test was conducted. 

(iii) If the maximum 6-minute opacity 

is less than 10 percent during the most 

recent Method 9 of appendix A–4 of this 

part performance test, the owner or 

operator may, as an alternative to 

performing subsequent Method 9 of 

appendix A–4 of this part performance 

tests, elect to perform subsequent 

monitoring using Method 22 of 

appendix A–7 of this part according to 

the procedures specified in paragraphs 

(a)(3)(iii)(A) and (B) of this section. 

(A) The owner or operator shall 

conduct 10 minute observations (during 

normal operation) each operating day 

the affected facility fires fuel for which 

an opacity standard is applicable using 

Method 22 of appendix A–7 of this part 

and demonstrate that the sum of the 

occurrences of any visible emissions is 

not in excess of 5 percent of the 

observation period (i.e., 30 seconds per 

10 minute period). If the sum of the 

occurrence of any visible emissions is 

greater than 30 seconds during the 

initial 10 minute observation, 

immediately conduct a 30 minute 

observation. If the sum of the 

occurrence of visible emissions is 

greater than 5 percent of the observation 

period (i.e., 90 seconds per 30 minute 

period) the owner or operator shall 

either document and adjust the 


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operation of the facility and 

demonstrate within 24 hours that the 

sum of the occurrence of visible 

emissions is equal to or less than 5 

percent during a 30 minute observation 

(i.e., 90 seconds) or conduct a new 

Method 9 of appendix A–4 of this part 

performance test using the procedures 

in paragraph (a)(3)(i) of this section 

within 30 calendar days according to 

the requirements in § 60.50Da(b)(3). 

(B) If no visible emissions are 

observed for 30 operating days during 

which an opacity standard is applicable, 

observations can be reduced to once 

every 7 operating days during which an 

opacity standard is applicable. If any 

visible emissions are observed, daily 

observations shall be resumed. 

(iv) If the maximum 6-minute opacity 

is less than 10 percent during the most 

recent Method 9 of appendix A–4 of this 

part performance test, the owner or 

operator may, as an alternative to 

performing subsequent Method 9 of 

appendix A–4 performance tests, elect 

to perform subsequent monitoring using 

a digital opacity compliance system 

according to a site-specific monitoring 

plan approved by the Administrator. 

The observations shall be similar, but 

not necessarily identical, to the 

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

this section. For reference purposes in 

preparing the monitoring plan, see 

OAQPS ‘‘Determination of Visible 

Emission Opacity from Stationary 

Sources Using Computer-Based 

Photographic Analysis Systems.’’ This 

document is available from the U.S. 

Environmental Protection Agency (U.S. 

EPA); Office of Air Quality and 

Planning Standards; Sector Policies and 

Programs Division; Measurement Policy 

Group (D243–02), Research Triangle 

Park, NC 27711. This document is also 

available on the Technology Transfer 

Network (TTN) under Emission 

Measurement Center Preliminary 

Methods. 

(b) * * * 

(4) If the owner or operator has 

installed and certified a SO2 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: 

* * * * * 

(iii) The reporting requirements of 

§ 60.51Da are met. The SO2 and, if 

required, 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. 

* * * * * 

(d) The owner or operator of an 

affected facility not complying with an 

output based limit 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. 

* * * * * 

(i) * * * 

(3) For affected facilities burning only 

fossil fuel, the span value for a COMS 

is between 60 and 80 percent. Span 

values for a CEMS measuring NOX shall 

be determined using one of the 

following procedures: 

* * * * * 

(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 §§ 60.42Da(c), 

60.43Da(i), 60.43Da(j), 60.44Da(d)(1), 

and 60.44Da(e). 

* * * * * 

(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 facility demonstrating 

compliance with the input-based 

emission limitation in § 60.42Da(a)(1) or 

§ 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) The owner or operator of an 

affected facility using a CEMS 

measuring CO emissions to meet 

requirements of this subpart shall meet 

the requirements specified in 

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

section. 

(1) You must monitor CO emissions 

using a CEMS according to the 

procedures specified in paragraphs 

(u)(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. 

The 1-hour averages are calculated 

using the data points required in 

§ 60.13(h)(2). 

(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 

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 facility. 

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. 

(3) You must evaluate the preceding 

24-hour average CO emission level each 

boiler operating day excluding periods 

of affected facility 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. 

(4) You must record the CO 

measurements and calculations 

performed according to paragraph (u)(3) 


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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)(4) of this section. 

* * * * * 

(2) During each PM correlation testing 

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 

performance tests conducted using the 

following test methods. 

(i) For PM, Method 5 or 5B of 

appendix A–3 of this part or Method 17 

of appendix A–6 of this part shall be 

used; and 

(ii) After July 1, 2010 or after Method 

202 of appendix M of part 51 has been 

revised to minimize artifact 

measurement and notice of that change 

has been published in the Federal 

Register, whichever is later, for 

condensable PM emissions, Method 202 

of appendix M of part 51 shall be used; 

and 

(iii) For O2 (or CO2), Method 3A or 3B 

of appendix A–2 of this part, as 

applicable shall be used. 

* * * * * 

(4) After July 1, 2011, within 90 days 

after the date of completing each 

performance evaluation required by 

paragraph (v) of this section, the owner 

or operator of the affected facility must 

either submit the test data to EPA by 

successfully entering the data 

electronically into EPA’s WebFIRE data 

base available at http://cfpub.epa.gov/ 

oarweb/index.cfm?action=fire.main or 

mail a copy to: United States 

Environmental Protection Agency; 

Energy Strategies Group; 109 TW 

Alexander DR; Mail Code: D243–01; 

RTP, NC 27711. 

(w) The owner or operator using a 

SO2, NOX, CO2, and O2 CEMS to meet 

the requirements of this subpart shall 

install, certify, operate, and maintain 

the CEMS as specified in paragraphs 

(w)(1) through (w)(5) of this section. 

(1) Except as provided for under 

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

this section, each 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. 

(2) As an alternative to meeting the 

requirements of paragraph (w)(1) of this 

section, an owner or operator 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 or equal to 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; 

* * * * * 

■ 12. Section 60.50Da is amended by 

revising paragraphs (e)(1) and (f) to read 

as follows: 

§ 60.50Da Compliance determination 

procedures and methods. 

* * * * * 

(e) * * * 

(1) For Method 5 or 5B of appendix 

A–3 of this part, Method 17 of appendix 

A–6 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 sections 8.1 and 11.1 of 

Method 5B of appendix A–3 of this part 

may be used in Method 17 of appendix 

A–6 of this part only if it is used after 

wet FGD systems. Method 17 of 

appendix A–6 of this part shall not be 

used after wet FGD systems if the 

effluent is saturated or laden with water 

droplets. 

* * * * * 

(f) Electric utility combined cycle gas 

turbines that are not designed to burn 

fuels containing 50 percent (by heat 

input) or more solid derived fuel not 

meeting the definition of natural gas are 

performance tested for PM, SO2, and 

NOX using the procedures of Method 19 

of appendix A–7 of this part. The SO2

and NOX emission rates calculations 

from the gas turbine used in Method 19 

of appendix A–7 of this part are 

determined when the gas turbine is 

performance tested under subpart GG of 

this part. The potential uncontrolled PM 

emission rate from a gas turbine is 

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

input. 

* * * * * 

■ 13. Section 60.51Da is amended by 

revising paragraphs (b)(2) and (b)(3) to 

read as follows: 

§ 60.51Da Reporting requirements. 

* * * * * 

(b) * * * 

(2) The average SO2 and NOX

emission rates (ng/J, lb/MMBtu, or lb/ 

MWh) for each 30 successive boiler 

operating days, ending with the last 30- 

day period in the quarter; reasons for 

non-compliance with the emission 

standards; and, description of corrective 

actions taken. 

(3) For owners or operators of affected 

facilities complying with the percent 

reduction requirement, 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 non-compliance 

with the standard; and, description of 

corrective actions taken. 

* * * * * 

■ 14. Section 60.52Da is revised to read 

as follows: 

§ 60.52Da Recordkeeping requirements. 

(a) 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). 

(b) The owner or operator of an 

affected facility subject to the opacity 

limits in § 60.42Da(b) that elects to 

monitor emissions according to the 

requirements in § 60.49Da(a)(3) shall 

maintain records according to the 

requirements specified in paragraphs 


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(b)(1) through (3) of this section, as 

applicable to the visible emissions 

monitoring method used. 

(1) For each performance test 

conducted using Method 9 of appendix 

A–4 of this part, the owner or operator 

shall keep the records including the 

information specified in paragraphs 

(b)(1)(i) through (iii) of this section. 

(i) Dates and time intervals of all 

opacity observation periods; 

(ii) Name, affiliation, and copy of 

current visible emission reading 

certification for each visible emission 

observer participating in the 

performance test; and 

(iii) Copies of all visible emission 

observer opacity field data sheets; 

(2) For each performance test 

conducted using Method 22 of appendix 

A–4 of this part, the owner or operator 

shall keep the records including the 

information specified in paragraphs 

(b)(2)(i) through (iv) of this section. 

(i) Dates and time intervals of all 

visible emissions observation periods; 

(ii) Name and affiliation for each 

visible emission observer participating 

in the performance test; 

(iii) Copies of all visible emission 

observer opacity field data sheets; and 

(iv) Documentation of any 

adjustments made and the time the 

adjustments were completed to the 

affected facility operation by the owner 

or operator to demonstrate compliance 

with the applicable monitoring 

requirements. 

(3) For each digital opacity 

compliance system, the owner or 

operator shall maintain records and 

submit reports according to the 

requirements specified in the sitespecific monitoring plan approved by 

the Administrator. 

Subpart Db—[Amended] 

■ 15. Section 60.40b is amended by 

revising the first sentence of paragraph 

(i) to read as follows: 

§ 60.40b Applicability and delegation of 

authority. 

* * * * * 

(i) Heat recovery steam generators that 

are associated with combined cycle gas 

turbines and that meet the applicability 

requirements of subpart KKKK of this 

part are not subject to this subpart. 

* * * 

* * * * * 

■ 16. Section 60.41b is amended by 

revising the definitions of ‘‘Coal,’’ 

‘‘Distillate oil,’’ ‘‘Gaseous fuel,’’ ‘‘Gross 

output,’’ ‘‘Natural gas,’’ ‘‘Potential sulfur 

dioxide emission rate,’’ ‘‘Steam 

generating unit,’’ and ‘‘Very low sulfur 

oil’’ to read as follows: 

§ 60.41b Definitions. 

* * * * * 

Coal means all solid fuels classified as 

anthracite, bituminous, subbituminous, 

or lignite by the American Society of 

Testing and Materials in ASTM D388 

(incorporated by reference, see § 60.17), 

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

not limited to solvent refined coal, 

gasified coal not meeting the definition 

of natural gas, coal-oil mixtures, coke 

oven gas, and coal-water mixtures, are 

also included in this definition for the 

purposes of this subpart. 

* * * * * 

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) or diesel fuel 

oil numbers 1 and 2, as defined by the 

American Society for Testing and 

Materials in ASTM D975 (incorporated 

by reference, see § 60.17). 

* * * * * 

Gaseous fuel means any fuel that is a 

gas at ISO conditions. This includes, but 

is not limited to, natural gas and 

gasified coal (including coke oven gas). 

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 or to enhance the performance of 

the unit (i.e., steam delivered to an 

industrial process). 

* * * * * 

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); 

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 dry standard cubic 

meter (910 and 1,150 Btu per dry 

standard cubic foot). 

* * * * * 

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. For gasified coal or oil 

that is desulfurized prior to combustion, 

the Potential sulfur dioxide emission 

rate is the theoretical SO2 emissions 

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

would result from combusting fuel in a 

cleaned state without using any post 

combustion emission control systems. 

* * * * * 

Steam generating unit means a device 

that combusts any fuel or byproduct/ 

waste and produces steam or heats 

water or heats any 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. 

* * * * * 

Very low sulfur oil means for units 

constructed, reconstructed, or modified 

on or before February 28, 2005, 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 and 

not located in a noncontinental area, 

very low sulfur oil means oil that 

contains no more than 0.30 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. For 

units constructed, reconstructed, or 

modified after February 28, 2005 and 

located in a noncontinental area, very 

low sulfur oil means 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 (0.50 

lb/MMBtu) heat input. 

■ 17. Section 60.42b is amended to read 

as follows: 

■ a. By revising paragraph (a); 

■ b. By revising paragraph (b); 

■ c. By revising paragraph (c); 

■ d. By revising paragraph (d) 

introductory text; and 

■ e. By revising paragraphs (k)(1), (k)(2), 

and (k)(3). 


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§ 60.42b Standard for sulfur dioxide (SO2). 

(a) Except as provided in paragraphs 

(b), (c), (d), or (j) 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). 

For facilities complying with the 

percent reduction standard, only the 

heat input supplied to the affected 

facility from the combustion of coal and 

oil is counted in this paragraph. 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 

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. 

For facilities complying with the 

percent reduction standard, only the 

heat input supplied to the affected 

facility from the combustion of coal and 

oil is counted in this paragraph. 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. 

(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). 

For facilities complying with the 

percent reduction standard, only the 

heat input supplied to the affected 

facility from the combustion of coal and 

oil is counted in this paragraph. 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. For 

facilities complying with paragraphs 

(d)(1), (2), or (3) of this section, only the 

heat input supplied to the affected 

facility from the combustion of coal and 

oil is counted in this paragraph. 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. 

* * * * * 

(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. For facilities complying with 

the percent reduction standard and 

paragraph (k)(3) of this section, only the 

heat input supplied to the affected 

facility from the combustion of coal and 

oil is counted in paragraph (k) of 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. 

(2) Units firing only very low sulfur 

oil, gaseous fuel, a mixture of these 

fuels, or a mixture of these fuels with 

any other 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 (k)(1) of this section. 

(3) Units that are located in a 

noncontinental area and that combust 

coal, oil, or natural gas 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 

or natural gas. 

* * * * * 

■ 18. Section 60.43b is amended to read 

as follows: 

■ a. By revising paragraph (f); 

■ b. By revising paragraph (g); and 

■ c. By revising paragraphs (h)(1) and 

(h)(5) and adding paragraph (h)(6). 


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5086 Federal Register / Vol. 74, No. 17 / Wednesday, January 28, 2009 / Rules and Regulations 

§ 60.43b Standard for particulate matter 

(PM). 

* * * * * 

(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 can combust 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. Owners and 

operators of an affected facility that 

elect to install, calibrate, maintain, and 

operate a continuous emissions 

monitoring system (CEMS) for 

measuring PM emissions according to 

the requirements of this subpart and are 

subject to a federally enforceable PM 

limit of 0.030 lb/MMBtu or less are 

exempt from the opacity standard 

specified in this paragraph. 

(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), (h)(5), 

and (h)(6) 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, 

* * * * * 

(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 

not located in a noncontinental area that 

commences construction, 

reconstruction, or modification after 

February 28, 2005, and that combusts 

only oil that contains no more than 0.30 

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 in § 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 

in (h)(1) of this section. 

(6) 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 

located in a noncontinental area that 

commences construction, 

reconstruction, or modification after 

February 28, 2005, and that combusts 

only oil that contains no more than 0.5 

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 in § 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 

in (h)(1) of this section. 

■ 19. Section 60.44b is amended by 

revising paragraph (l)(1) to read as 

follows: 

§ 60.44b Standard for nitrogen oxides 

(NOX). 

* * * * * 

(l) * * * 

(1) If the affected facility combusts 

coal, oil, natural gas, a mixture of these 

fuels, or a mixture of these fuels 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 

* * * * * 

■ 20. Section 60.45b is amended to read 

as follows: 

■ a. By revising paragraph (a); 

■ b. By revising paragraphs (c)(2)(i), 

(c)(4) introductory text, and (c)(5); 

■ c. By revising paragraph (d) 

introductory text; 

■ d. By revising paragraph (j); and 

■ e. By revising paragraph (k). 

§ 60.45b Compliance and performance test 

methods and procedures for sulfur dioxide. 

(a) The SO2 emission standards in 

§ 60.42b apply at all times. Facilities 

burning coke oven gas alone or in 

combination with any other gaseous 

fuels or distillate oil are allowed to 

exceed the limit 30 operating days per 

calendar year for SO2 control system 

maintenance. 

* * * * * 

(c) * * * 

(2) * * * 

(i) The procedures in Method 19 of 

appendix A–7 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 CEMS of § 60.47b(a) 

or (b). 

* * * * * 

(4) The owner or operator of an 

affected facility subject to paragraph 

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

measure parameters Ew or Xk if the 

owner or operator elects to assume that 

Xk= 1.0. Owners or operators of affected 

facilities who assume Xk = 1.0 shall: 

* * * * * 

(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 in 

paragraph (c)(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 in 

Method 19 of appendix A–7 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, natural gas, or a 

mixture of these fuels, 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: 

* * * * * 

(j) The owner or operator of an 

affected facility that only combusts very 

low sulfur oil, natural gas, or a mixture 

of these fuels with any other fuels not 

subject to an SO2 standard 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 in §§ 60.42b(d)(4), 60.42b(j), 

60.42b(k)(2), and 60.42b(k)(3) (when not 

burning coal) shall follow the applicable 

procedures in § 60.49b(r). 

■ 21. Section 60.46b is amended to read 

as follows: 

■ a. By revising paragraphs (d)(1) and 

(d)(2)(ii); 

■ b. By revising paragraphs (e)(2) and 

(e)(4); 

■ c. By revising paragraph (g); 

■ d. By revising paragraph (i); and 

■ e. By revising paragraphs (j) 

introductory text and (j)(11) and adding 

paragraph (j)(14). 

§ 60.46b Compliance and performance test 

methods and procedures for particulate 

matter and nitrogen oxides. 

* * * * * 

(d) * * * 

(1) Method 3A or 3B of appendix A– 

2 of this part is used for gas analysis 

when applying Method 5 of appendix 


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A–3 of this part or Method 17 of 

appendix A–6 of this part. 

(2) * * * 

(ii) Method 17 of appendix A–6 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 (320 °F). 

The procedures of sections 8.1 and 11.1 

of Method 5B of appendix A–3 of this 

part may be used in Method 17 of 

appendix A–6 of this part only if it is 

used after a wet FGD system. Do not use 

Method 17 of appendix A–6 of this part 

after wet FGD systems if the effluent is 

saturated or laden with water droplets. 

* * * * * 

(e) * * * 

(2) Following the date on which the 

initial performance test is completed or 

is required to be completed in § 60.8, 

whichever date comes first, the owner 

or operator of an affected facility which 

combusts coal (except as specified 

under § 60.46b(e)(4)) or which combusts 

residual oil having a nitrogen content 

greater than 0.30 weight percent shall 

determine compliance with the NOX

emission standards in § 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 for 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, gasified coal, 

or residual oil having a nitrogen content 

of 0.30 weight percent or less shall upon 

request determine compliance with the 

NOX standards in § 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. 

* * * * * 

(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 or the heat input 

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 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. 

* * * * * 

(i) The owner or operator of an 

affected facility seeking to demonstrate 

compliance with the PM limit in 

paragraphs § 60.43b(a)(4) or 

§ 60.43b(h)(5) shall follow the 

applicable procedures in § 60.49b(r). 

(j) In place of PM testing with Method 

5 or 5B of appendix A–3 of this part, or 

Method 17 of appendix A–6 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 Method 5 or 

5B of appendix A–3 of this part or 

Method 17 of appendix A–6 of this part 

shall comply with the requirements 

specified in paragraphs (j)(1) through 

(j)(14) of this section. 

* * * * * 

(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 performance 

tests conducted using the following test 

methods. 

(i) For PM, Method 5 or 5B of 

appendix A–3 of this part or Method 17 

of appendix A–6 of this part shall be 

used; and 

(ii) After July 1, 2010 or after Method 

202 of appendix M of part 51 has been 

revised to minimize artifact 

measurement and notice of that change 

has been published in the Federal 

Register, whichever is later, for 

condensable PM emissions, Method 202 

of appendix M of part 51 shall be used; 

and 

(iii) For O2 (or CO2), Method 3A or 3B 

of appendix A–2 of this part, as 

applicable shall be used. 

* * * * * 

(14) After July 1, 2011, within 90 days 

after completing a correlation testing 

run, the owner or operator of an affected 

facility shall either successfully enter 

the test data into EPA’s WebFIRE data 

base located at http://cfpub.epa.gov/ 

oarweb/index.cfm?action=fire.main or 

mail a copy to: United States 

Environmental Protection Agency; 

Energy Strategies Group; 109 TW 

Alexander DR; Mail Code: D243–01; 

RTP, NC 27711. 

* * * * * 

■ 22. Section 60.47b is amended by 

revising the first sentence of paragraph 

(a) introductory text and the first 

sentence of paragraph (e)(4)(i) to read as 

follows: 

§ 60.47b Emission monitoring for sulfur 

dioxide. 

(a) Except as provided in paragraphs 

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

operator of an affected facility subject to 

the SO2 standards in § 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. 

* * * 

* * * * * 

(e) * * * 

(4) * * * 

(i) For all required CO2 and O2

monitors and for SO2 and NOX monitors 

with span values greater than or equal 

to 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. * * * 

* * * * * 

■ 23. Section 60.48b is amended to read 

as follows: 


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■ a. By revising paragraph (a); 

■ b. By revising paragraph (e)(1); 

■ c. By revising paragraph (g) 

introductory text; 

■ d. By revising paragraph (h); 

■ e. By revising paragraphs (j) 

introductory text, the last sentence of 

(j)(4) introductory text, (j)(4)(i)(C), (j)(5) 

and adding (j)(6); and 

■ f. By revising the first sentence of 

paragraph (k). 

§ 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 

continuous opacity monitoring systems 

(COMS) for measuring the opacity of 

emissions discharged to the atmosphere 

and record the output of the system. The 

owner or operator of an affected facility 

subject to an opacity standard under 

§ 60.43b and meeting the conditions 

under paragraphs (j)(1), (2), (3), (4), or 

(5) of this section who elects not to 

install a COMS shall conduct a 

performance test using Method 9 of 

appendix A–4 of this part and the 

procedures in § 60.11 to demonstrate 

compliance with the applicable limit in 

§ 60.43b and shall comply with either 

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

section. If during the initial 60 minutes 

of observation all 6-minute averages are 

less than 10 percent and all individual 

15-second observations are less than or 

equal to 20 percent, the observation 

period may be reduced from 3 hours to 

60 minutes. 

(1) Except as provided in paragraph 

(a)(2) and (a)(3) of this section, the 

owner or operator shall conduct 

subsequent Method 9 of appendix A–4 

of this part performance tests using the 

procedures in paragraph (a) of this 

section according to the applicable 

schedule in paragraphs (a)(1)(i) through 

(a)(1)(iv) of this section, as determined 

by the most recent Method 9 of 

appendix A–4 of this part performance 

test results. 

(i) If no visible emissions are 

observed, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 12 

calendar months from the date that the 

most recent performance test was 

conducted; 

(ii) If visible emissions are observed 

but the maximum 6-minute average 

opacity is less than or equal to 5 

percent, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 6 

calendar months from the date that the 

most recent performance test was 

conducted; 

(iii) If the maximum 6-minute average 

opacity is greater than 5 percent but less 

than or equal to 10 percent, a 

subsequent Method 9 of appendix A–4 

of this part performance test must be 

completed within 3 calendar months 

from the date that the most recent 

performance test was conducted; or 

(iv) If the maximum 6-minute average 

opacity is greater than 10 percent, a 

subsequent Method 9 of appendix A–4 

of this part performance test must be 

completed within 30 calendar days from 

the date that the most recent 

performance test was conducted. 

(2) If the maximum 6-minute opacity 

is less than 10 percent during the most 

recent Method 9 of appendix A–4 of this 

part performance test, the owner or 

operator may, as an alternative to 

performing subsequent Method 9 of 

appendix A–4 of this part performance 

tests, elect to perform subsequent 

monitoring using Method 22 of 

appendix A–7 of this part according to 

the procedures specified in paragraphs 

(a)(2)(i) and (ii) of this section. 

(i) The owner or operator shall 

conduct 10 minute observations (during 

normal operation) each operating day 

the affected facility fires fuel for which 

an opacity standard is applicable using 

Method 22 of appendix A–7 of this part 

and demonstrate that the sum of the 

occurrences of any visible emissions is 

not in excess of 5 percent of the 

observation period (i.e., 30 seconds per 

10 minute period). If the sum of the 

occurrence of any visible emissions is 

greater than 30 seconds during the 

initial 10 minute observation, 

immediately conduct a 30 minute 

observation. If the sum of the 

occurrence of visible emissions is 

greater than 5 percent of the observation 

period (i.e., 90 seconds per 30 minute 

period) the owner or operator shall 

either document and adjust the 

operation of the facility and 

demonstrate within 24 hours that the 

sum of the occurrence of visible 

emissions is equal to or less than 5 

percent during a 30 minute observation 

(i.e., 90 seconds) or conduct a new 

Method 9 of appendix A–4 of this part 

performance test using the procedures 

in paragraph (a) of this section within 

30 calendar days according to the 

requirements in § 60.46d(d)(7). 

(ii) If no visible emissions are 

observed for 30 operating days during 

which an opacity standard is applicable, 

observations can be reduced to once 

every 7 operating days during which an 

opacity standard is applicable. If any 

visible emissions are observed, daily 

observations shall be resumed. 

(3) If the maximum 6-minute opacity 

is less than 10 percent during the most 

recent Method 9 of appendix A–4 of this 

part performance test, the owner or 

operator may, as an alternative to 

performing subsequent Method 9 of 

appendix A–4 performance tests, elect 

to perform subsequent monitoring using 

a digital opacity compliance system 

according to a site-specific monitoring 

plan approved by the Administrator. 

The observations shall be similar, but 

not necessarily identical, to the 

requirements in paragraph (a)(2) of this 

section. For reference purposes in 

preparing the monitoring plan, see 

OAQPS ‘‘Determination of Visible 

Emission Opacity from Stationary 

Sources Using Computer-Based 

Photographic Analysis Systems.’’ This 

document is available from the U.S. 

Environmental Protection Agency (U.S. 

EPA); Office of Air Quality and 

Planning Standards; Sector Policies and 

Programs Division; Measurement Policy 

Group (D243–02), Research Triangle 

Park, NC 27711. This document is also 

available on the Technology Transfer 

Network (TTN) under Emission 

Measurement Center Preliminary 

Methods. 

* * * * * 

(e) * * * 

(1) For affected facilities combusting 

coal, wood or municipal-type solid 

waste, the span value for a COMS shall 

be between 60 and 80 percent. 

* * * * * 

(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, gasified coal, 

or any mixture of these fuels, greater 

than 10 percent (0.10) shall: 

* * * * * 

(h) The owner or operator of a duct 

burner, as described in § 60.41b, that is 

subject to the NOX standards in 

§ 60.44b(a)(4), § 60.44b(e), or § 60.44b(l) 

is not required to install or operate a 

continuous emissions monitoring 

system to measure NOX emissions. 

* * * * * 

(j) The owner or operator of an 

affected facility that meets the 

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

(3), (4), (5), or (6) of this section is not 

required to install or operate a COMS if: 

* * * * * 

(4) * * * Owners and 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; or 


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(i) * * * 

(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. 

The 1-hour averages are calculated 

using the data points required in 

§ 60.13(h)(2). 

* * * * * 

(5) The affected facility uses a bag 

leak detection system to monitor the 

performance of a fabric filter (baghouse) 

according to the most recent 

requirements in section § 60.48Da of 

this part; or 

(6) 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 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 must calibrate, maintain, 

operate, and record the output of the 

system for PM emissions discharged to 

the atmosphere as specified in 

§ 60.46b(j). * * * 

■ 24. Section 60.49b is amended to read 

as follows: 

■ a. By revising paragraphs (c) 

introductory text and (c)(3); 

■ b. By revising paragraph (d); 

■ c. By revising paragraph (f); 

■ d. By revising paragraph (h)(1) and 

(h)(2)(i); 

■ e. By revising paragraph (k)(2); 

■ f. By revising paragraph (m) 

introductory text; and 

■ g. By revising paragraph (r)(1). 

§ 60.49b Reporting and recordkeeping 

requirements. 

* * * * * 

(c) The owner or operator of each 

affected facility subject to the NOX

standard in § 60.44b who seeks to 

demonstrate compliance with those 

standards through the monitoring of 

steam generating unit operating 

conditions in the provisions of 

§ 60.48b(g)(2) shall submit to the 

Administrator for approval a plan that 

identifies the operating conditions to be 

monitored in § 60.48b(g)(2) and the 

records to be maintained in § 60.49b(g). 

This plan shall be submitted to the 

Administrator for approval within 360 

days of the initial startup of the affected 

facility. An affected facility burning 

coke oven gas alone or in combination 

with other gaseous fuels or distillate oil 

shall submit this plan to the 

Administrator for approval within 360 

days of the initial startup of the affected 

facility or by November 30, 2009, 

whichever date comes later. 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: 

* * * * * 

(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 

maintained by the owner or operator 

under § 60.49b(g). 

(d) Except as provided in paragraph 

(d)(2) of this section, the owner or 

operator of an affected facility shall 

record and maintain records as specified 

in paragraph (d)(1) of this section. 

(1) 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. 

(2) As an alternative to meeting the 

requirements of paragraph (d)(1) of this 

section, the owner or operator of an 

affected facility that is subject to a 

federally enforceable permit restricting 

fuel use to a single fuel such that the 

facility is not required to continuously 

monitor any emissions (excluding 

opacity) or parameters indicative of 

emissions may elect to record and 

maintain records of the amount of each 

fuel combusted during each calendar 

month. 

* * * * * 

(f) For an affected facility subject to 

the opacity standard in § 60.43b, the 

owner or operator shall maintain 

records of opacity. In addition, an 

owner or operator that elects to monitor 

emissions according to the requirements 

in § 60.48b(a) shall maintain records 

according to the requirements specified 

in paragraphs (f)(1) through (3) of this 

section, as applicable to the visible 

emissions monitoring method used. 

(1) For each performance test 

conducted using Method 9 of appendix 

A–4 of this part, the owner or operator 

shall keep the records including the 

information specified in paragraphs 

(f)(1)(i) through (iii) of this section. 

(i) Dates and time intervals of all 

opacity observation periods; 

(ii) Name, affiliation, and copy of 

current visible emission reading 

certification for each visible emission 

observer participating in the 

performance test; and 

(iii) Copies of all visible emission 

observer opacity field data sheets; 

(2) For each performance test 

conducted using Method 22 of appendix 

A–4 of this part, the owner or operator 

shall keep the records including the 

information specified in paragraphs 

(f)(2)(i) through (iv) of this section. 

(i) Dates and time intervals of all 

visible emissions observation periods; 

(ii) Name and affiliation for each 

visible emission observer participating 

in the performance test; 

(iii) Copies of all visible emission 

observer opacity field data sheets; and 

(iv) Documentation of any 

adjustments made and the time the 

adjustments were completed to the 

affected facility operation by the owner 

or operator to demonstrate compliance 

with the applicable monitoring 

requirements. 

(3) For each digital opacity 

compliance system, the owner or 

operator shall maintain records and 

submit reports according to the 

requirements specified in the sitespecific monitoring plan approved by 

the Administrator. 

* * * * * 

(h) * * * 

(1) Any affected facility subject to the 

opacity standards in § 60.43b(f) or to the 

operating parameter monitoring 

requirements in § 60.13(i)(1). 

(2) * * * 

(i) Combusts natural gas, distillate oil, 

gasified coal, or residual oil with a 

nitrogen content of 0.3 weight percent 

or less; or 

* * * * * 

(k) * * * 

(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; For an 

exceedance due to maintenance of the 

SO2 control system covered in 

paragraph 60.45b(a), the report shall 

identify the days on which the 


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maintenance was performed and a 

description of the maintenance; 

* * * * * 

(m) For each affected facility subject 

to the SO2 standards in § 60.42(b) for 

which the minimum amount of data 

required in § 60.47b(c) 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: 

* * * * * 

(r) * * * 

(1) The owner or operator of an 

affected facility who elects to 

demonstrate that the affected facility 

combusts only very low sulfur oil, 

natural gas, wood, a mixture of these 

fuels, or any of these fuels (or a mixture 

of these fuels) in combination with 

other fuels that are known to contain an 

insignificant amount of sulfur in 

§ 60.42b(j) or § 60.42b(k) 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 and gaseous fuel meets 

the definition of natural gas 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, natural gas, 

wood, and/or other fuels that are known 

to contain insignificant amounts of 

sulfur were combusted in the affected 

facility during the reporting period; or 

* * * * * 

Subpart Dc—[Amended] 

■ 25. Section 60.40c is amended to read 

as follows: 

■ a. By revising paragraph (a); 

■ b. By revising the first sentence of 

paragraph (e); 

■ c. By revising paragraph (f); and 

■ d. By revising paragraph (g). 

§ 60.40c Applicability and delegation of 

authority. 

(a) Except as provided in paragraphs 

(d), (e), (f), and (g) 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). 

* * * * * 

(e) Heat recovery steam generators 

that are associated with combined cycle 

gas turbines and meet the applicability 

requirements of subpart KKKK of this 

part are not subject to this subpart. 

* * * 

(f) Any facility covered by subpart 

AAAA of this part is not subject 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 subject by this 

subpart. 

■ 26. Section 60.41c is amended by 

revising the definitions of ‘‘Coal,’’ 

‘‘Distillate oil,’’ ‘‘Natural gas,’’ and 

‘‘Steam generating unit’’ to read as 

follows: 

§ 60.41c Definitions. 

* * * * * 

Coal means all solid fuels classified as 

anthracite, bituminous, subbituminous, 

or lignite by the American Society of 

Testing and Materials in ASTM D388 

(incorporated by reference, see § 60.17), 

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 not 

meeting the definition of natural gas, 

coal-oil mixtures, and coal-water 

mixtures, are also included in this 

definition for the purposes of this 

subpart. 

* * * * * 

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) or diesel fuel 

oil numbers 1 or 2, as defined by the 

American Society for Testing and 

Materials in ASTM D975 (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) Liquefied petroleum (LP) gas, as 

defined by the American Society for 

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 dry standard cubic 

meter (910 and 1,150 Btu per dry 

standard cubic foot). 

* * * * * 

Steam generating unit means a device 

that combusts any fuel and produces 

steam or heats water or heats any 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. 

* * * * * 

■ 27. Section 60.42c is amended by 

revising paragraphs (e)(2) and (j) to read 

as follows: 

§ 60.42c Standard for sulfur dioxide (SO2). 

* * * * * 

(e) * * * 

(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 = Heat input from the combustion of oil, 

in J (MMBtu). 

* * * * * 

(j) For affected facilities located in 

noncontinental areas and affected 

facilities complying with the percent 

reduction standard, only the heat input 

supplied to the affected facility from the 


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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. 

■ 28. Section 60.43c is amended by 

revising paragraph (c) to read as follows: 

§ 60.43c Standard for particulate matter 

(PM). 

* * * * * 

(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 can 

combust 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. Owners and 

operators of an affected facility that 

elect to install, calibrate, maintain, and 

operate a continuous emissions 

monitoring system (CEMS) for 

measuring PM emissions according to 

the requirements of this subpart and are 

subject to a federally enforceable PM 

limit of 0.030 lb/MMBtu or less are 

exempt from the opacity standard 

specified in this paragraph. 

* * * * * 

■ 29. Section 60.44c is amended by 

revising paragraph (h) to read as 

follows: 

§ 60.44c Compliance and performance test 

methods and procedures for sulfur dioxide. 

* * * * * 

(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 from the fuel supplier, as 

described in § 60.48c(f), as applicable. 

* * * * * 

■ 30. Section 60.45c is amended to read 

as follows: 

■ a. By revising paragraphs (a)(2) and 

(a)(8); 

■ b. By revising paragraphs (c) 

introductory text, (c)(7) introductory 

text, (c)(8), (c)(9), and (c)(11), and by 

adding paragraph (c)(14). 

§ 60.45c Compliance and performance test 

methods and procedures for particulate 

matter. 

(a) * * * 

(2) Method 3A or 3B of appendix A– 

2 of this part shall be used for gas 

analysis when applying Method 5 or 5B 

of appendix A–3 of this part or 17 of 

appendix A–6 of this part. 

* * * * * 

(8) Method 9 of appendix A–4 of this 

part shall be used for determining the 

opacity of stack emissions. 

* * * * * 

(c) In place of PM testing with Method 

5 or 5B of appendix A–3 of this part or 

Method 17 of appendix A–6 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 Method 5 or 

5B of appendix A–3 of this part or 

Method 17 of appendix A–6 of this part 

shall install, calibrate, maintain, and 

operate a CEMS and shall comply with 

the requirements specified in 

paragraphs (c)(1) through (c)(14) of this 

section. 

* * * * * 

(7) At a minimum, valid CEMS hourly 

averages shall be obtained as specified 

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

75 percent of the total operating hours 

per 30-day rolling average. 

* * * * * 

(8) The 1-hour arithmetic averages 

required under paragraph (c)(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 

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

* * * * * 

(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 performance 

tests conducted using the following test 

methods. 

(i) For PM, Method 5 or 5B of 

appendix A–3 of this part or Method 17 

of appendix A–6 of this part shall be 

used; and 

(ii) After July 1, 2010 or after Method 

202 of appendix M of part 51 has been 

revised to minimize artifact 

measurement and notice of that change 

has been published in the Federal 

Register, whichever is later, for 

condensable PM emissions, Method 202 

of appendix M of part 51 shall be used; 

and 

(iii) For O2 (or CO2), Method 3A or 3B 

of appendix A–2 of this part, as 

applicable shall be used. 

* * * * * 

(14) After July 1, 2011, within 90 days 

after the date of completing each 

performance evaluation required by 

paragraph (c)(11) of this section, the 

owner or operator of the affected facility 

must either submit the test data to EPA 

by successfully entering the data 

electronically into EPA’s WebFIRE data 

base available at http://cfpub.epa.gov/ 

oarweb/index.cfm?action=fire.main or 

mail a copy to: United States 

Environmental Protection Agency; 

Energy Strategies Group; 109 TW 

Alexander DR; Mail Code: D243–01; 

RTP, NC 27711. 

* * * * * 

■ 31. Section 60.47c is amended to read 

as follows: 

■ a. By revising paragraph (a); 

■ b. By revising paragraph (b); 

■ c. By revising paragraph (c); 

■ d. By revising paragraph (d); 

■ e. By revising paragraphs (e) 

introductory text and (e)(1)(iii); 

■ f. By revising paragraph (f); and 

■ g. By adding paragraph (g). 

§ 60.47c Emission monitoring for 

particulate matter. 

(a) Except as provided in paragraphs 

(c), (d), (e), (f), and (g) 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 continuous 

opacity monitoring system (COMS) for 

measuring the opacity of the emissions 

discharged to the atmosphere and 

record the output of the system. The 

owner or operator of an affected facility 

subject to an opacity standard in 

§ 60.43c(c) and that is not required to 

install a COMS due to paragraphs (c), 

(d), (e), or (f) of this section that elects 

not to install a COMS shall conduct a 

performance test using Method 9 of 

appendix A–4 of this part and the 

procedures in § 60.11 to demonstrate 

compliance with the applicable limit in 

§ 60.43c and shall comply with either 

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

section. If during the initial 60 minutes 

of observation all 6-minute averages are 

less than 10 percent and all individual 

15-second observations are less than or 

equal to 20 percent, the observation 

period may be reduced from 3 hours to 

60 minutes. 


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(1) Except as provided in paragraph 

(a)(2) and (a)(3) of this section, the 

owner or operator shall conduct 

subsequent Method 9 of appendix A–4 

of this part performance tests using the 

procedures in paragraph (a) of this 

section according to the applicable 

schedule in paragraphs (a)(1)(i) through 

(a)(1)(iv) of this section, as determined 

by the most recent Method 9 of 

appendix A–4 of this part performance 

test results. 

(i) If no visible emissions are 

observed, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 12 

calendar months from the date that the 

most recent performance test was 

conducted; 

(ii) If visible emissions are observed 

but the maximum 6-minute average 

opacity is less than or equal to 5 

percent, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 6 

calendar months from the date that the 

most recent performance test was 

conducted; 

(iii) If the maximum 6-minute average 

opacity is greater than 5 percent but less 

than or equal to 10 percent, a 

subsequent Method 9 of appendix A–4 

of this part performance test must be 

completed within 3 calendar months 

from the date that the most recent 

performance test was conducted; or 

(iv) If the maximum 6-minute average 

opacity is greater than 10 percent, a 

subsequent Method 9 of appendix A–4 

of this part performance test must be 

completed within 30 calendar days from 

the date that the most recent 

performance test was conducted. 

(2) If the maximum 6-minute opacity 

is less than 10 percent during the most 

recent Method 9 of appendix A–4 of this 

part performance test, the owner or 

operator may, as an alternative to 

performing subsequent Method 9 of 

appendix A–4 of this part performance 

tests, elect to perform subsequent 

monitoring using Method 22 of 

appendix A–7 of this part according to 

the procedures specified in paragraphs 

(a)(2)(i) and (ii) of this section. 

(i) The owner or operator shall 

conduct 10 minute observations (during 

normal operation) each operating day 

the affected facility fires fuel for which 

an opacity standard is applicable using 

Method 22 of appendix A–7 of this part 

and demonstrate that the sum of the 

occurrences of any visible emissions is 

not in excess of 5 percent of the 

observation period (i.e. , 30 seconds per 

10 minute period). If the sum of the 

occurrence of any visible emissions is 

greater than 30 seconds during the 

initial 10 minute observation, 

immediately conduct a 30 minute 

observation. If the sum of the 

occurrence of visible emissions is 

greater than 5 percent of the observation 

period (i.e. , 90 seconds per 30 minute 

period) the owner or operator shall 

either document and adjust the 

operation of the facility and 

demonstrate within 24 hours that the 

sum of the occurrence of visible 

emissions is equal to or less than 5 

percent during a 30 minute observation 

(i.e. , 90 seconds) or conduct a new 

Method 9 of appendix A–4 of this part 

performance test using the procedures 

in paragraph (a) of this section within 

30 calendar days according to the 

requirements in § 60.45c(a)(8). 

(ii) If no visible emissions are 

observed for 30 operating days during 

which an opacity standard is applicable, 

observations can be reduced to once 

every 7 operating days during which an 

opacity standard is applicable. If any 

visible emissions are observed, daily 

observations shall be resumed. 

(3) If the maximum 6-minute opacity 

is less than 10 percent during the most 

recent Method 9 of appendix A–4 of this 

part performance test, the owner or 

operator may, as an alternative to 

performing subsequent Method 9 of 

appendix A–4 performance tests, elect 

to perform subsequent monitoring using 

a digital opacity compliance system 

according to a site-specific monitoring 

plan approved by the Administrator. 

The observations shall be similar, but 

not necessarily identical, to the 

requirements in paragraph (a)(2) of this 

section. For reference purposes in 

preparing the monitoring plan, see 

OAQPS ‘‘Determination of Visible 

Emission Opacity from Stationary 

Sources Using Computer-Based 

Photographic Analysis Systems.’’ This 

document is available from the U.S. 

Environmental Protection Agency (U.S. 

EPA); Office of Air Quality and 

Planning Standards; Sector Policies and 

Programs Division; Measurement Policy 

Group (D243–02), Research Triangle 

Park, NC 27711. This document is also 

available on the Technology Transfer 

Network (TTN) under Emission 

Measurement Center Preliminary 

Methods. 

(b) All COMS shall be operated in 

accordance with the 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) Owners and operators of an 

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 (0.060 

lb/MMBtu) heat input or less and that 

do not use a post-combustion 

technology to reduce SO2 or PM 

emissions and that are subject to an 

opacity standard in § 60.43c(c) are not 

required to operate a COMS if they 

follow the applicable procedures in 

§ 60.48c(f). 

(d) Owners or operators complying 

with the PM emission limit by using a 

PM CEMS must calibrate, maintain, 

operate, and record the output of the 

system for PM emissions discharged to 

the atmosphere as specified in 

§ 60.45c(c). The CEMS specified in 

paragraph § 60.45c(c) 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) Owners and operators of an 

affected facility that is subject to an 

opacity standard in § 60.43c(c) and 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 discharged 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. 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; or 

(1) * * * 

(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. 

The 1-hour averages are calculated 

using the data points required in 

§ 60.13(h)(2). 

* * * * * 

(f) Owners and operators of an 

affected facility that is subject to an 

opacity standard in § 60.43c(c) and that 

uses a bag leak detection system to 

monitor the performance of a fabric 

filter (baghouse) according to the most 

recent requirements in section § 60.48Da 

of this part is not required to operate a 

COMS. 

(g) Owners and operators of an 

affected facility that is subject to an 

opacity standard in § 60.43c(c) and 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 


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Federal Register / Vol. 74, No. 17 / Wednesday, January 28, 2009 / Rules and Regulations 5093 

approved by the permitting authority is 

not required to operate a COMS. 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. 

■ 32. Section 60.48c is amended to read 

as follows: 

■ a. By revising paragraph (c); 

■ b. By revising paragraph (e)(11); and 

■ c. By revising paragraphs (f)(1)(iii) and 

(f)(4)(ii). 

§ 60.48c Reporting and recordkeeping 

requirements. 

* * * * * 

(c) In addition to the applicable 

requirements in § 60.7, the owner or 

operator of an affected facility subject to 

the opacity limits in § 60.43c(c) shall 

submit excess emission reports for any 

excess emissions from the affected 

facility that occur during the reporting 

period and maintain records according 

to the requirements specified in 

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

section, as applicable to the visible 

emissions monitoring method used. 

(1) For each performance test 

conducted using Method 9 of appendix 

A–4 of this part, the owner or operator 

shall keep the records including the 

information specified in paragraphs 

(c)(1)(i) through (iii) of this section. 

(i) Dates and time intervals of all 

opacity observation periods; 

(ii) Name, affiliation, and copy of 

current visible emission reading 

certification for each visible emission 

observer participating in the 

performance test; and 

(iii) Copies of all visible emission 

observer opacity field data sheets; 

(2) For each performance test 

conducted using Method 22 of appendix 

A–4 of this part, the owner or operator 

shall keep the records including the 

information specified in paragraphs 

(c)(2)(i) through (iv) of this section. 

(i) Dates and time intervals of all 

visible emissions observation periods; 

(ii) Name and affiliation for each 

visible emission observer participating 

in the performance test; 

(iii) Copies of all visible emission 

observer opacity field data sheets; and 

(iv) Documentation of any 

adjustments made and the time the 

adjustments were completed to the 

affected facility operation by the owner 

or operator to demonstrate compliance 

with the applicable monitoring 

requirements. 

(3) For each digital opacity 

compliance system, the owner or 

operator shall maintain records and 

submit reports according to the 

requirements specified in the sitespecific monitoring plan approved by 

the Administrator 

* * * * * 

(e) * * * 

(11) If 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) * * * 

(1) * * * 

(iii) The sulfur content or maximum 

sulfur content of the oil. 

* * * * * 

(4) * * * 

(ii) The potential sulfur emissions rate 

or maximum potential sulfur emissions 

rate of the fuel in ng/J heat input; and 

* * * * * 

[FR Doc. E9–523 Filed 1–27–09; 8:45 am] 

BILLING CODE 6560–50–P 


sroberts on PROD1PC70 with RULES