Vol. 77 Wednesday, 

No. 168 August 29, 2012 

Part III 

Environmental Protection Agency 

40 CFR Part 60 

Standards of Performance for Stationary Gas Turbines; Standards of 

Performance for Stationary Combustion Turbines; Proposed Rule 


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52554 Federal Register / Vol. 77, No. 168 / Wednesday, August 29, 2012 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[EPA–HQ–OAR–2004–0490; FRL–9695–6] 

RIN 2060–AQ29 

Standards of Performance for 

Stationary Gas Turbines; Standards of 

Performance for Stationary 

Combustion Turbines 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The EPA is proposing to 

amend the new source performance 

standards (NSPS) for stationary gas 

turbines and stationary combustion 

turbines. These amendments are 

primarily in response to issues raised by 

the regulated community. On July 6, 

2006, the EPA promulgated 

amendments to the new source 

performance standards for stationary 

combustion turbines. On September 5, 

2006, the Utility Air Regulatory Group 

filed a petition for reconsideration of 

certain aspects of the promulgated 

standards. The EPA is proposing to 

amend specific provisions in the NSPS 

to resolve issues and questions raised by 

the petition for reconsideration, and to 

address other technical and editorial 

issues. In addition, this proposed rule 

would amend the location and wording 

of existing paragraphs for clarity. The 

proposed amendments would increase 

the environmental benefits of the 

existing requirements because the 

emission standards would apply at all 

times. The proposed amendments 

would also promote efficiency by 

recognizing the environmental benefit of 

combined heat and power and the 

beneficial use of low energy content 

gases. 

DATES: Comments must be received on 

or before October 29, 2012. 

Public Hearing. If anyone contacts the 

EPA by September 10, 2012 requesting 

to speak at a public hearing, the EPA 

will hold a public hearing on or about 

September 13, 2012. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2004–0490, by one of the 

following methods: 

• http://www.regulations.gov: Follow 

the on-line instructions for submitting 

comments. 

• Email: a-and-r-docket@epa.gov. 

• Fax: (202) 566–9744. 

• Mail: Air and Radiation Docket, 

U.S. EPA, Mail Code 6102T, 1200 

Pennsylvania Ave. NW., Washington, 

DC 20460. Please include a total of two 

copies. 

• Hand Delivery: EPA Docket Center, 

Docket ID Number EPA–HQ–OAR– 

2004–0490, EPA West Building, 1301 

Constitution Ave. NW., Room 3334, 

Washington, DC, 20004. Such deliveries 

are accepted only during the Docket’s 

normal hours of operation, and special 

arrangements should be made for 

deliveries of boxed information. 

Instructions: Direct your comments to 

Docket ID No. EPA–HQ–OAR–2004– 

0490. The EPA’s policy is that all 

comments received will be included in 

the public docket without change and 

may be made available online at http:// 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through regulations.gov or 

email. Send or deliver information 

identified as CBI only to the following 

address: Roberto Morales, OAQPS 

Document Control Officer (C404–02), 

Office of Air Quality Planning and 

Standards, Environmental Protection 

Agency, Research Triangle Park, North 

Carolina 27711, Attention Docket ID No. 

EPA–HQ–OAR–2004–0490. Clearly 

mark the part or all of the information 

that you claim to be CBI. For CBI 

information in a disk or CD–ROM that 

you mail to the EPA, mark the outside 

of the disk or CD–ROM as CBI and then 

identify electronically within the disk or 

CD–ROM the specific information that 

is claimed as CBI. In addition to one 

complete version of the comment that 

includes information claimed as CBI, a 

copy of the comment that does not 

contain the information claimed as CBI 

must be submitted for inclusion in the 

public docket. Information so marked 

will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. The http:// 

www.regulations.gov Web site is an 

‘‘anonymous access’’ system, which 

means the EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to the EPA without 

going through www.regulations.gov, 

your email address will be 

automatically captured and included as 

part of the comment that is placed in the 

public docket and made available on the 

Internet. If you submit an electronic 

comment, the EPA recommends that 

you include your name and other 

contact information in the body of your 

comment and with any disk or CD–ROM 

you submit. If the EPA cannot read your 

comment due to technical difficulties 

and cannot contact you for clarification, 

the EPA may not be able to consider 

your comment. Electronic files should 

avoid the use of special characters, any 

form of encryption, and be free of any 

defects or viruses. For additional 

information about the EPA’s public 

docket visit the EPA Docket Center 

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

dockets/. 

Docket: All documents in the docket 

are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly available docket 

materials are available either 

electronically in http:// 

www.regulations.gov or in hard copy at 

the Air and Radiation Docket EPA/DC, 

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 

and Radiation Docket is (202) 566–1742. 

Public Hearing: If a public hearing is 

requested, it will be held at the EPA 

Facility Complex in Research Triangle 

Park, North Carolina or at an alternate 

site nearby. Contact Ms. Pamela Garrett 

at (919) 541–7966 to request a hearing, 

to request to speak at a public hearing, 

to determine if a hearing will be held, 

or to determine the hearing location. 

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 

(email) address: 

fellner.christian@epa.gov. 

SUPPLEMENTARY INFORMATION: Regulated 

Entities: Entities potentially affected by 

this proposed action include, but are not 

limited to, the following: 


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Category NAICS1 Examples of regulated entities 

Industry ........................................................ 2211 Electric services. 

486210 Natural gas transmission. 

211111 Crude petroleum and natural gas. 

211112 Natural gas liquids. 

221 Electric and other services, combined. 

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 proposed rule. To 

determine whether your facility is 

regulated by this proposed rule, you 

should examine the applicability 

criteria in §§ 60.4305 and 60.4310. If 

you have any questions regarding the 

applicability of this proposed rule to a 

particular entity, contact the person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section. 

WorldWide Web (WWW): Following 

the Administrator’s signature, a copy of 

the proposed amendments will be 

posted on the Technology Transfer 

Network’s (TTN) policy and guidance 

page for newly proposed or promulgated 

rules at http://www.epa.gov/ttn/oarpg. 

The TTN provides information and 

technology exchange in various areas of 

air pollution control. 

Outline: The information presented in 

this preamble is organized as follows: 

I. Background 

II. Proposed Amendments 

A. Applicability 

B. NOX Emissions Standard 

C. SO2 Emissions Standard 

D. Malfunction Affirmative Defense 

E. Electronic Data Submittal 

F. Additional Proposed Amendments 

G. Additional Request for Comments 

III. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

(UMRA) 

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. 

I. Background 

On July 6, 2006, the EPA promulgated 

revised new source performance 

standards (NSPS) for stationary 

combustion turbines (subpart KKKK of 

40 CFR part 60) applicable to stationary 

combustion turbines on which 

construction, modification or 

reconstruction is commenced after 

February 18, 2005 (71 FR 38482). The 

new standards in subpart KKKK reflect 

advances in turbine design and nitrogen 

oxide (NOX) emission control 

technologies since the standards for 

these units were originally promulgated 

in 1979 in subpart GG of 40 CFR part 

60 (44 FR 52798). The new standards 

also reflect the use of lower sulfur fuels. 

A petition for reconsideration of the 

revised NSPS was filed by the Utility 

Air Regulatory Group on September 5, 

2006. The EPA has decided to grant 

reconsideration of subpart KKKK to the 

extent specified in this proposed rule. 

The amendments proposed by this 

action address issues for which the 

petitioners specifically requested 

reconsideration (see docket entry EPA– 

HQ–OAR–2004–0490–0325) and other 

matters as described below. 

As part of this action, the EPA is also 

proposing to amend other rule language 

to correct technical omissions, 

typographical errors, grammatical errors 

and to address various other issues that 

have been identified since 

promulgation. A significant issue 

identified since promulgation is the 

development of new stationary 

combustion technologies that are 

capable of burning a variety of lowBritish thermal units (Btu) gases. The 

amendments proposed in this action 

include amending the sulfur dioxide 

(SO2) standard for all low-Btu gases 

similar to the biogas (i.e., landfill gas) 

standard currently in subpart KKKK. 

The proposed amendments would not 

change the EPA’s original projections 

for this proposed rule’s compliance 

costs, environmental benefits, burden 

on industry or the number of affected 

facilities. The EPA is also proposing 

limited conforming amendments to 

subpart GG. 

Finally, the EPA is proposing to 

amend subpart KKKK to exempt some 

stationary combustion turbines from the 

emission standards in subpart KKKK. 

First, owners/operators of stationary 

combustion turbines that meet the 

applicability criteria of, and that are 

complying with the SO2 standard in, 

either subpart J or Ja (standards of 

performance for petroleum refineries) 

would be exempt from complying with 

the otherwise applicable SO2 standard 

in subpart KKKK. In addition, owners/ 

operators of stationary combustion 

turbines covered that meet the 

applicability criteria of, and that are 

complying with the SO2 and NOX

standards in subparts Ea, Eb, Cd, AAAA 

or BBBB (the municipal solid waste 

regulations) would be exempt from 

complying with the otherwise 

applicable SO2 and NOX standards in 

subpart KKKK. 

II. Proposed Amendments 

We are proposing to amend subparts 

GG and KKKK of 40 CFR part 60 to 

clarify the intent in applying and 

implementing specific rule 

requirements, to correct unintentional 

technical omissions and editorial errors, 

and address various other issues that 

have been identified since the 

promulgation of subpart KKKK. A 

summary of the proposed substantive 

amendments to the NSPS for stationary 

combustion turbines and the rationale 

for these amendments are below. 

In addition, we are proposing to 

amend 40 CFR 60.17 (incorporations by 

reference) and republish subpart KKKK 

in its entirety. The proposed 

amendments include updating 40 CFR 

60.17 to include additional test methods 

identified in subpart KKKK and revising 

the wording and writing style to clarify 

the requirements of the NSPS. We do 

not intend for these editorial revisions 

to substantively change any of the 

technical or administrative 

requirements of the subpart and have 

concluded that they do not do so. To the 

extent that we determine that the 

editorial revisions do effect any 

unintended substantive changes, we 

will correct the problem in taking final 

action on the proposed rule. 

A. Applicability 

We are proposing to make five 

amendments to the applicability of 

subpart KKKK of 40 CFR part 60. First, 


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the combustion turbine engine (the air 

compressor, combustor and turbine 

sections) is the primary source of 

emissions from a stationary combustion 

turbine. However, due to the broad 

definition of the affected facility in 

subpart KKKK, the combustion turbine 

engine does not necessarily constitute 

the majority of the costs of a new 

stationary combustion turbine. The 

expanded definition of a stationary 

combustion turbine in subpart KKKK is 

intended to simplify compliance and 

recognize the environmental benefit of 

heat recovery at combined cycle and 

combined heat and power (CHP) 

facilities. It is not intended to change 

the circumstances in which a turbine 

engine is designated as new or 

reconstructed. However, under subpart 

KKKK it is not clear whether a CHP or 

combined cycle facility that replaces the 

turbine engine would be considered 

‘‘new’’ or ‘‘reconstructed.’’ The existing 

language in subpart KKKK could be 

interpreted to mean that replacement of 

a turbine engine with a new turbine 

engine at an existing combined cycle or 

CHP facility not currently subject to 

subpart KKKK would result in the new 

turbine engine being subject to subpart 

GG. In that case, the heat recovery steam 

generator (HRSG) would continue to 

comply with the same boiler NSPS as 

prior to the turbine engine replacement 

and two NSPS would apply to the 

facility. It was clearly not the intent 

when subpart KKKK was promulgated 

that these turbine engines would only 

be subject to emission control 

technologies that were available in the 

1970s. In this situation, combustion 

controls have the same cost 

effectiveness as other new or 

reconstructed turbine engines. In 

addition, compliance is minimally 

impacted by the design of the HRSG, so 

there is no reason that two pieces of 

equipment should not be combined. 

Since the subpart KKKK standards are 

input-based, with optional alternative 

output-based standards, the efficiency of 

the HRSG is not essential for 

demonstrating compliance. Further, the 

presence of duct burners should not 

significantly impact the emissions rate 

since typical low NOX natural gas-fired 

duct burners contribute between 15 to 

25 parts per million (ppm) NOX

corrected to 15 percent oxygen (O2) and 

ultra low NOX duct burners are 

available that only contribute 

approximately 3 ppm NOX corrected to 

15 percent O2. Therefore, while we are 

maintaining the broad definition of an 

affected facility, we are proposing that 

for the purposes of determining 

applicability and if a stationary 

combustion turbine is ‘‘new’’ or 

‘‘reconstructed,’’ only the combustion 

turbine engine itself will be considered. 

This approach reflects the 

environmental benefits of heat recovery 

and output-based standards and was the 

intent of the original rule. This rule as 

amended would make it clear that the 

replacement of a turbine engine at a 

CHP or combined cycle facility that is 

not currently subject to subpart KKKK 

with a new turbine engine would result 

in the establishment of a new stationary 

combustion turbine under subpart 

KKKK, as was intended when subpart 

KKKK was promulgated. Furthermore, 

the addition of a new turbine engine to 

an existing HRSG would result in the 

establishment of a new stationary 

combustion turbine under subpart 

KKKK that includes the existing heat 

recovery steam generating unit. 

However, the construction or 

reconstruction of a HRSG associated 

with a turbine engine covered by 

subpart GG would not result in the 

entire facility being subject to subpart 

KKKK. A positive aspect of this 

approach is that the most current 

subpart KKKK requirements would 

apply to turbine engines that are 

replaced at combined cycle and CHP 

facilities already subject to subpart 

KKKK. 

In the event the final rule does not 

include this clarification, the stationary 

combustion engine replaced at an 

existing combined cycle or CHP facility 

would be covered by subpart GG, and 

the HRSG would be covered by the 

applicable steam generating unit NSPS. 

Subpart GG would be amended to 

include NOX emission standards for 

turbine engines that are identical to 

those in Table 1 of subpart KKKK. The 

subpart GG SO2 emission standards and 

the monitoring, testing and reporting 

requirements would also be amended to 

be identical to the requirements for 

simple cycle turbines subject to subpart 

KKKK. With this approach, subpart GG 

would have to be amended each time 

that the subpart KKKK standards are 

amended. To provide additional 

compliance flexibility, we would add 

the ability for owners/operators of new 

and reconstructed turbine engine 

replacements at existing combined cycle 

and CHP facilities to petition the 

Administrator to voluntarily comply 

with the new and reconstructed 

requirements, as applicable, in subpart 

KKKK as an alternative to 

demonstrating compliance with 

amended subpart GG and applicable 

boiler NSPS separately. This approach 

would provide an equivalent amount of 

environmental protection as the 

previously described approach. 

However, we have concluded that the 

previously described approach avoids 

petition requirement and would reduce 

the regulatory burden of the proposed 

rule. We specifically request comment 

on the level of environmental protection 

and regulatory burden for each 

approach. A disadvantage of this 

approach is that the most current 

subpart KKKK requirements would not 

apply to turbine engines that are 

replaced at combined cycle and CHP 

facilities already subject to subpart 

KKKK. We are requesting comment if 

this approach could be amended to 

assure that future amended subpart 

KKKK requirements would apply to 

new and reconstructed turbine engines. 

Second, we are proposing to exempt 

owners/operators of stationary 

combustion turbines that meet the 

applicability requirements and that are 

complying with the SO2 standard in 

either subparts J or Ja of 40 CFR part 60 

(Standards of performance for 

petroleum refineries) from complying 

with the otherwise applicable SO2

standard in subpart KKKK. The SO2

standard in both subparts J and Ja is 

more stringent than in subpart KKKK, so 

this proposed amendment would 

simplify compliance for owner/ 

operators of petroleum refineries 

without an increase in pollutant 

emissions. In addition, owners/ 

operators of stationary combustion 

turbines covered that meet the 

applicability criteria of, and that are 

complying with, the SO2 and NOX

standards in subparts Ea, Eb, Cd, AAAA 

or BBBB (the municipal solid waste 

regulations) would be exempt from 

complying with the otherwise 

applicable SO2 and NOX standards in 

subpart KKKK. The SO2 standards in the 

municipal solid waste rules are more 

stringent than in subpart KKKK, so this 

proposed amendment would simplify 

compliance for owner/operators of 

petroleum refineries without an increase 

in pollutant emissions. 

Third, we are proposing to exempt 

owners/operators of stationary 

combustion turbines that are subject to 

a federally enforceable permit limiting 

fuel to gaseous fuels containing no more 

than 20 grains of sulfur per 100 standard 

cubic feet (scf) and/or liquid fuels 

containing no more than 0.050 weight 

percent sulfur (500 ppm sulfur by 

weight) from the SO2 standard. Both of 

these fuels have potential SO2 emissions 

of less than 0.060 pounds per million 

British thermal units (lb/MMBtu) and 

would be in compliance with the SO2

standard. The proposed amendment 

would reduce the burden for owners/ 

operators burning natural gas and 


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distillate oil of complying with subpart 

KKKK by limiting reporting and 

recordkeeping costs without increasing 

emissions. 

Fourth, we are proposing to allow 

owners/operators of stationary 

combustion turbines currently covered 

by subpart GG and any associated steam 

generating unit subject to an NSPS to 

have the option to petition the 

Administrator to comply with subpart 

KKKK in lieu of complying with subpart 

GG and any associated steam generating 

unit NSPS. Since the applicability of 

subpart KKKK encompasses any 

associated heat recovery equipment, 

owners/operators would have the 

flexibility to comply with one NSPS 

instead of multiple NSPS. The 

Administrator will only grant the 

petition if he/she determines that 

compliance with subpart KKKK would 

be equivalent to, or more stringent than, 

compliance with subpart GG and any 

associated steam generating unit NSPS. 

For example, assuming equal amounts 

of fuel are combusted in the turbine and 

duct burners (HRSG), an existing oilfired combined cycle combustion 

turbine subject separately to subpart GG 

and subpart Db of 40 CFR part 60 would 

have an equivalent combined NOX

emissions standard of approximately 65 

parts per million (ppm). By contrast, the 

subpart KKKK NOX standard for 

modified turbines burning fuels other 

than natural gas is 96 ppm. The 

Administrator would, therefore, deny 

the petition in such circumstances. We 

have concluded that this is only an 

issue for turbines burning fuels other 

than natural gas. Also, we are clarifying 

that if any solid fuel as defined in 

subpart KKKK is burned in the HRSG, 

the HRSG would be covered by the 

applicable steam generating unit NSPS 

and not subpart KKKK. We are not 

aware of any existing stationary 

combustion turbines that burn solid fuel 

in the HRSG, but the intent of this 

proposed rule is to cover only liquid 

and gaseous fuels. The amendment 

would prevent a large solid fuel-fired 

boiler from using the exhaust from a 

combustion turbine engine in order to 

avoid the requirements of the applicable 

steam generating unit NSPS. 

Finally, we are requesting comment 

on how to address combustion turbine 

engines that are overhauled or 

refurbished off site in such a manner 

that neither the owner, operator nor 

manufacturer can identify which 

components have been replaced and, 

therefore, cannot conduct the otherwise 

required reconstruction analysis. The 

owner/operator of a turbine engine that 

is overhauled or refurbished in such a 

manner that each individual component 

of the engine is tracked would still 

perform the traditional reconstruction 

analysis, i.e., the owner/operator would 

compare the total cost of replacement 

components with the cost of a 

comparable new turbine engine. In 

general, a reconstructed facility is one 

which has had components replaced to 

the extent that the fixed capital costs of 

the new components exceeds 50 percent 

of the fixed capital cost that would be 

required to construct a comparable 

entirely new facility. (See 40 CFR 

60.15.) 

We are requesting comment on two 

potential approaches for dealing with 

circumstances where there is 

insufficient information to determine 

which components of a particular 

combustion turbine engine have been 

replaced. The first approach would base 

the reconstruction test on changes to the 

combustor alone. (That is, the test 

would be whether the fixed capital cost 

of the replacement combustor exceeds 

50 percent of the fixed capital cost that 

would be required to install a 

comparable new combustor.) The 

alternate approach would be based on 

the number of times a particular turbine 

engine has been refurbished. Potential 

language for both approaches is as 

follows: 

1. An overhauled or refurbished turbine 

engine where neither the owner/operator nor 

manufacturer can identify which components 

have been replaced shall be considered 

reconstructed if the combustor itself is either 

replaced or reconstructed (as specified under 

§ 60.15). When such information is known, 

an owner or operator of a turbine engine that 

is overhauled or refurbished shall perform a 

reconstruction analysis on the entire turbine 

engine as described under § 60.15. 

The corresponding definition for a 

combustor would be: 

A combustor means a component or area 

in a combustion turbine engine where fuel is 

added to the pressurized air molecules and 

combustion takes place. It is also known as 

a burner or flame can. 

2. An overhauled or refurbished turbine 

engine where neither the owner/operator nor 

manufacturer can identify which components 

have been replaced during the most recent 

and previous two refurbishments shall be 

considered reconstructed. When such 

information is known, an owner or operator 

of a turbine engine that is overhauled or 

refurbished shall perform a reconstruction 

analysis on the turbine engine as described 

under § 60.15. 

If this provision is adopted, it would 

provide an owner/operator with relative 

certainty that they could potentially 

operate a combustion turbine for 

approximately 90,000 hours, or over 10 

years of continuous operation, before 

triggering the reconstruction provisions 

in subpart KKKK. (Assuming that 

turbine exchanges take place at 

approximately 30,000 operating hour 

intervals.) This approach would provide 

relative regulatory certainty for both the 

owner/operator of the combustion 

turbine and the turbine manufacturer. 

We are also requesting comment on 

the frequency of an entire combustor 

replacement. It is our understanding 

that combustion liners and the fuel 

injection system are replaced at 

intervals similar to major overhauls, but 

that the combustor need not be replaced 

in entirety. If this is the case, then the 

‘‘combustor’’ approach could 

inadvertently hinder emissions 

improvements by providing an 

incentive to replace only the critical 

components of the combustor instead of 

upgrading the entire combustor. A 

potential alternative approach would be 

to limit the applicability of the 

combustor to the combustion liner and 

fuel injection system such that once 

those components are replaced the 

combustion turbine would be 

considered reconstructed. Assuming the 

replacement intervals are similar to 

overhaul intervals, if we adopt this 

approach in the final rule, we would 

consider two replacements prior to 

triggering reconstruction. 

Finally, we are requesting comment 

on whether a similar approach should 

be adopted for turbines that are 

overhauled onsite. It is our 

understanding that larger combustion 

turbines operating on natural gas have 

overhaul schedules of approximately 

every 50,000 operating hours. Under 

these assumptions, a combustion 

turbine could potentially operate 

continuously for over 17 years prior to 

triggering the amended reconstruction 

provision under subpart KKKK. 

If we adopt reconstruction triggers 

that differ from the general provisions, 

we intend to maintain the qualification 

that it is technologically and 

economically feasible to meet the 

applicable standards for each 

combustion turbine that triggers the 

amended reconstruction provisions. 

Instances where it might not be 

economically feasible would be made 

on a case-by-case basis by the 

Administrator. Examples of situations 

where it might not be economically 

feasible to meet the emissions standard 

include low NOX combustor designs 

being unavailable, turbine designs that 

are not compatible with water or steam 

injection, or demineralized water or 

steam required for NOX control being 

unavailable. 

In addition to the above proposed 

amendments to the applicability of 

Subpart KKKK to new, reconstructed, 

and modified stationary combustion 


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turbines, we are proposing to exempt 

non-major sources subject to this NSPS 

from title V permitting requirements. 

Under the Clean Air Act (CAA) section 

502(a), the EPA may exempt non-major 

sources subject to CAA section 111 

(NSPS) standards from the requirements 

of title V if the EPA finds that 

compliance with such requirements is 

‘‘impracticable, infeasible, or 

unnecessarily burdensome’’ on such 

sources. The EPA’s finding to support 

exemption of non-major source 

stationary combustion turbines subject 

to Subparts GG and KKKK from the title 

V permitting requirements is available 

in the docket. 

B. NOX Emissions Standard 

We are proposing to amend the NOX

emissions standard for stationary 

combustion turbines that burn multiple 

fuels. The existing rule bases the 

applicable NOX standard on the total 

heat input to the stationary combustion 

turbine, including any associated duct 

burners, and the more stringent 

standard is only applicable if the total 

heat input is derived from at least 50 

percent natural gas. However, fuel 

choice impacts combustion turbine 

engine NOX emissions to a greater 

degree than it impacts such emissions 

from a duct burner. Therefore, we are 

proposing that the NOX standard be 

based on the type of fuel being burned 

in the combustion turbine engine alone. 

The natural gas standard would apply at 

those times when the fuel input to the 

combustion turbine engine meets the 

definition of natural gas, regardless of 

the fuel, if any, that is burned in the 

duct burners. 

We are also proposing to add a 

provision allowing for a site-specific 

NOX standard for an owner/operator of 

a stationary combustion turbine that 

burns by-product fuels. The owner/ 

operator would be required to petition 

the Administrator for a site-specific 

standard using a procedure similar to 

what is currently required by subpart Db 

of 40 CFR part 60 (the industrial boiler 

NSPS). We have concluded that this is 

appropriate since subpart KKKK now 

covers the HRSG that was previously 

covered by subpart Db. 

Since startup and shutdowns are part 

of the regular operating practices of 

stationary combustion turbines, we are 

proposing that the NOX emissions 

standard includes startup and shutdown 

emissions. Since periods of startup and 

shutdown are by definition periods of 

low load, the ‘‘part-load standard’’ 

would apply to all hours that contain a 

startup or shutdown event. Since the 

‘‘part-load standard’’ is based on the 

emissions rate of a diffusion flame and 

not dry low NOX (DLN) combustion 

controls, we have concluded this 

standard is appropriate. Through 

analysis of continuous emission 

monitoring system (CEMS) data, we 

have determined that including periods 

of startup and shutdown in the standard 

would not result in non-compliance 

with the standard. We analyzed NOX

continuous CEMS data from existing 

large and small turbines without postcombustion controls to reduce NOX

emissions. Even though many of these 

turbines were built prior to the 

applicability date of subpart KKKK, the 

theoretical compliance rate with a 4- 

hour rolling average including all 

periods of operation was greater than 99 

percent for both large and small 

turbines. We were unable to determine 

if any of the potential excess emissions 

were a result of either malfunction of 

the NOX CEMS or combustion control 

equipment, or identify all periods when 

the ‘‘part-load standard’’ would apply 

and the actual level of theoretical 

compliance would be higher. Even 

though the theoretical compliance rate 

is high when the NOX emissions 

standard is determined directly, we are 

specifically requesting comment on 

whether to account for startup 

conditions by considering the first 30 

minutes of operation ‘‘part-load’’ such 

that the part-load emissions rate would 

apply during that time period regardless 

of the actual load. Implementing this 

option increases the theoretical 

compliance rate. 

Since we only used performance test 

data and did not analyze NOX CEMS 

data in the original rulemaking, we are 

requesting comment on whether it is 

appropriate to extend the averaging time 

for simple cycle turbines to an operating 

day average. Emissions averages would 

only be determined for operating days 

with 3 or more hours of CEMS data that 

are not out-of-control. Data from 

operating days with less than 3 hours of 

CEMS data that are not out-of-control 

would be rolled over to the next 

operating day until 3 or more hours of 

data are available. Extending the 

averaging period to an operating daily 

average would increase the theoretical 

compliance rate. However, since 

combustion turbines using combustion 

controls tend to have a steady emissions 

profile, we have concluded that this 

approach would not result in an 

increase in emissions, and could lower 

compliance burden by reducing the 

reporting burden. An additional benefit 

of this approach is that all non out-ofcontrol emissions data would be used in 

determining excess emissions. Under 

the current approach, any 4 operating 

hours with more than 1 hour of monitor 

downtime is reported as monitor 

downtime and the emissions from the 

remaining hours are excluded. We are 

not proposing a longer averaging period 

for a simple cycle turbine. If we were to 

use a longer averaging period for simple 

cycle turbines or determine compliance 

during startup, shutdown and part-load 

periods separately from full-load 

periods, the NOX standards would be reevaluated to determine appropriate 

standards. Furthermore, we are 

proposing to add a lb/MMBtu NOX

option that is equivalent to the ppm 

standard. This option would simplify 

compliance for some sources while 

providing the same level of 

environmental protection. Fourth, based 

on analysis of the CEMS data, we are 

proposing to change the classification of 

large/small for turbines operating at 

part-load. The existing rule divides 

large/small turbines operating at partload based on the rated output of the 

turbine (i.e., turbines with outputs 

greater than 30 megawatts (MW) are 

considered large). This proposed 

amendment would divide large/small 

turbines operating at part-load based on 

the rated heat input (i.e., turbines with 

base load heat inputs greater 340 

MMBtu per hour (MMBtu/h) would be 

considered large). A heat input rating of 

340 MMBtu/h is approximately 

equivalent to an output rating of 30 

MW, and this amendment would 

simplify compliance by making the 

measurement method for determination 

the large/small part-load subcategory 

consistent with how the other 

subcategories are determined. A 

detailed discussion of the NOX CEMS 

data for both large and small turbines is 

available in the docket. 

We have concluded that the net 

power supplied to the end user is a 

better indication of environmental 

performance than gross output from the 

power producer. Therefore, we intend to 

amend the optional output-based 

standard from gross to net output in the 

final rule. Net output is the combination 

of the gross electrical (or mechanical) 

output of the turbine engine and any 

output generated by the HRSG minus 

the parasitic power requirements. A 

parasitic load for a stationary 

combustion turbine is any of the loads 

or devices powered by electricity, 

steam, hot water or directly by the gross 

output of the stationary combustion 

turbine that does not contribute 

electrical, mechanical or thermal 

output. One reason for this amendment 

is that while combustion turbine 

engines that require high fuel gas feed 

pressures typically have higher gross 


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efficiencies, they also often require fuel 

compressors that have potentially larger 

parasitic loads than combustion turbine 

engines that require lower fuel gas 

pressures. We have concluded that 

primary parasitic loads include the fuel 

compressor, pump, or heater, fans, inlet 

air cooling systems, control systems and 

post combustion controls. We are 

requesting comment on any additional 

loads that should be considered. To 

account for the parasitic loads, we 

intend to lower the efficiency 

assumptions used to generate the 

output-based standards. We have 

concluded that a 2.5 percent difference 

in efficiency is appropriate, but are 

requesting comment on the issue. As an 

alternative to continuously monitoring 

parasitic loads, we have concluded that 

estimating parasitic loads is adequate 

and would minimize compliance costs. 

A calibration would be required to 

determine the parasitic loads at four 

load points (< 25 percent load, 25–50 

percent load, 50–75 percent load, and 

>75 percent load). Once the parasitic 

load curve is determined, the 

appropriate amount would be 

subtracted from the gross output to 

determine net output. We are requesting 

comment on this approach and whether 

a four-load test is appropriate or if a 

curve fit of three loads greater than 25 

percent load is sufficient. 

In addition, we are proposing to 

recognize the environmental benefit of 

electricity generated by CHP facilities to 

account for the benefit of on-site 

generation avoiding losses from the 

transmissions and distribution of the 

electricity. Actual line losses vary from 

location to location, but we are 

proposing a benefit of five percent 

avoided transmission and distribution 

losses when determining the electric 

output for CHP facilities. To avoid CHP 

facilities only providing a trivial amount 

of thermal energy from qualifying for 

the transmission and distribution 

benefit, we are proposing to restrict the 

5 percent benefit to CHP facilities where 

at least 20 percent of the annual output 

is useful thermal output. 

Finally, we are requesting comment 

on limiting the use of the 30-day 

average. The existing rule provides a 30- 

day averaging period for owners/ 

operators of combined cycle and CHP 

turbines regardless of if they elect to 

comply with the input or output-based 

standard. However, based on the review 

of CEMS data, NOX emissions from 

stationary combustion turbines are 

relatively stable in terms of ppm or lb/ 

MMBtu and a 30-day averaging time for 

combined cycle and CHP facilities is not 

necessary. Owner/operators of any 

stationary combustion turbine 

(including combined cycle and CHP 

turbines) electing to comply with either 

of the input-based standards (ppm or lb/ 

MMBtu) would be required to use the 4- 

hour (or daily) averaging period. The 

existing rule does not provide owner/ 

operators of simple cycle turbines the 

option to demonstrate compliance using 

a 30-day average. We have concluded 

that few owner/operators of simple 

cycle turbines would elect to 

demonstrate compliance with the 

output-based standard, but as 

technology develops this might change 

in the future. Therefore, since output is 

the only relevant characteristic that 

varies significantly over short periods 

and a longer averaging period is 

necessary to account for periods of 

lower efficiency, we are requesting 

comment on using the 30-day averaging 

period for owner/operators of any 

stationary combustion turbine electing 

to demonstrate compliance with the 

output-based standard. Owner/operators 

of all stationary combustion turbines 

electing to demonstrate compliance 

with either the ppm or lb/MMBtu 

standards would use a 4-hour (or daily) 

averaging period. 

C. SO2 Emissions Standard 

We are proposing to amend the rule 

language to clarify the intent of the rule 

in that if a source elects to perform fuel 

analysis to demonstrate compliance 

with the SO2 standard, the initial test 

must measure all sulfur compounds (e.g. 

hydrogen sulfide, dimethyl sulfide, 

carbonyl sulfide and thiol compounds). 

Alternate test procedures can be used 

only if the measured sulfur content is 

less than half of the applicable standard. 

In addition, we are proposing to allow 

fuel blending to achieve the applicable 

SO2 standard. Under the proposed 

language, an owner/operator of an 

affected facility would be able to burn 

higher sulfur fuels as long as the average 

fuel fired meets the applicable SO2

standard at all times. Finally, the 

primary method of controlling SO2

emissions is through selecting fuels 

containing low amounts of sulfur or 

through fuel pretreatment operations 

that can operate at all times. We are 

proposing that the SO2 standard apply 

during periods of startup and shutdown. 

In recognition that ultra-low sulfur 

diesel is available for transportation 

purposes in Hawaii, the Commonwealth 

of Puerto Rico and the Virgin Islands, 

we are removing these areas from the 

definition of noncontinental area. The 

only difference for owners/operators of 

affected stationary combustion turbines 

located in noncontinental areas is the 

ability to burn higher sulfur fuels. We 

have concluded that since these areas 

have low sulfur diesel oil available it is 

not appropriate to include these 

locations in the noncontinental area 

definition. This amendment would still 

allow the use of higher sulfur fuels in 

Guam, American Samoa, the Northern 

Mariana Islands and offshore platforms 

where lower sulfur fuels are not 

necessarily as readily accessible. 

For stationary combustion turbines 

combusting 50 percent or more biogas 

(based on total heat input) per calendar 

month, the existing Subpart KKKK 

establishes a maximum allowable SO2

emissions standard of 65 nanograms 

(ng) SO2 per joule (/J) (0.15 lb SO2/ 

MMBtu) heat input. This standard was 

set to avoid discouraging the 

development of energy recovery 

projects, which burn landfill gases to 

generate electricity in stationary 

combustion turbines (see 74 FR 11858, 

March 20, 2009). New stationary 

combustion technologies using other 

low-Btu gases are becoming 

commercially available. These 

technologies can burn low-Btu content 

gases recovered from steelmaking (e.g., 

blast furnace gas and coke oven gas), 

coal bed methane, closed landfills, etc. 

Similar to biogas, substantial 

environmental benefits can be achieved 

by using these low-Btu gases to generate 

electricity instead of flaring or direct 

venting to the atmosphere, as is now 

common practice. Therefore, we are 

proposing to expand the application of 

the existing 65 ng SO2/J (0.15 lb SO2/ 

MMBtu) heat input emissions standard 

to include stationary combustion 

turbines combusting 50 percent or more 

(on a heat input basis) of any gaseous 

fuels that have heating values less than 

26 megajoules per standard cubic meter 

(700 Btu per scf) per calendar month. 

To account for the environmental 

benefit of productive use and simplify 

compliance for low-Btu gases, we have 

concluded that it is appropriate to base 

the SO2 standard on a fuel concentration 

basis as an alternative to a lb/MMBtu 

basis. The original subpart KKKK 2005 

proposal (70 FR 8314) SO2 standard was 

based on the sulfur content in distillate 

oil and included a sulfur standard of 

0.05 percent by weight (500 ppm by 

weight (ppmw)). However, since we are 

proposing to exempt liquid fuels 

containing less than 0.050 weight 

percent sulfur from the SO2 standard, 

we are proposing an alternate standard 

of 500 ppm by volume (ppmv). In 

general, emission standards are applied 

to a gaseous mixture are by volume 

(ppmv), not by weight (ppmw). Basing 

the standard on a volume basis would 

simplify compliance and minimize 

burden to the regulated community. 

Therefore, we are proposing a fuel 


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specification standard of 650 milligrams 

per standard cubic meter (28 gr/100 scf) 

for low-Btu gases. This is approximately 

equivalent to a standard of 500 ppmv, 

and is in the units directly reported by 

most test methods. 

D. Malfunction Affirmative Defense 

The EPA has proposed standards in 

this proposed rule that apply at all times 

and is proposing to add an affirmative 

defense to civil penalties that are caused 

by malfunctions. The EPA’s finding to 

support the malfunction affirmative 

defense is available in the docket. 

E. Electronic Data Submittal 

The EPA is proposing that owners/ 

operators of stationary combustion 

turbines submit electronic copies of 

required performance test reports to the 

EPA’s WebFIRE database. The EPA’s 

finding to support this requirement is 

available in the docket. 

F. Additional Proposed Amendments 

We are also proposing several 

additional amendments. First, we have 

concluded that it is not appropriate to 

require an affected facility that is not 

currently in operation to startup to 

demonstrate compliance with the NSPS. 

Commencing operation strictly for the 

purposes of demonstrating compliance 

is an unnecessary cost and increases 

emissions. Therefore, we are proposing 

to exempt units that are out of operation 

at the time of the required performance 

test from conducting the required 

performance test until 45 days after the 

facility is brought back into operation. 

Similarly, owner/operators of a 

combustion turbine that has operated 50 

hours or less since the previous 

performance test was required to be 

conducted can request an extension of 

the otherwise required performance test 

from the appropriate EPA Regional 

Office until the turbine has operated 

over 50 hours. This provision is fuel 

specific and an owner/operator 

permitted to burn a backup fuel, but that 

rarely does so, can request an extension 

on testing on that particular fuel until it 

has been burned for over 50 hours. 

In addition, for similar, separate 

affected facilities using identical control 

equipment, the Administrator or 

delegated authority may authorize a 

single emissions test as adequate 

demonstration for up to four other 

similar, separate affected facilities as 

long as: (1) The most recent 

performance test for each affected 

facility shows that performance of each 

affected facility is 75 percent or less of 

the applicable emissions standard; (2) 

the manufacturer’s recommended 

maintenance procedures for each 

control device are followed; and (3) 

each affected facility conducts a 

performance test for each pollutant for 

which they are subject to a standard at 

least once every five years. DLN 

combustion controls are the primary 

method for compliance with the NSPS 

requirements and result in relatively 

stable emission rates. Furthermore, the 

DLN combustor is a fundamental part of 

a combustion turbine and as long as 

similar maintenance procedures are 

followed we have concluded that 

emission rates will likely be comparable 

between similar combustion turbines. 

Therefore, the additional compliance 

costs associated with testing each 

affected turbine would not result in 

significant emissions reductions. 

Additionally, turbine engine 

performance can deteriorate with 

operation and age and operational 

parameters need to be verified 

periodically to assure proper operation 

of emission controls. Therefore, we are 

proposing to require facilities using the 

water or steam to fuel ratio as a 

demonstration of continuous 

compliance with the NOX emissions 

standard to verify the appropriate ratio 

or parameters at a minimum of every 60 

months. We have concluded this would 

not add significant burden since the 

majority of affected facilities are already 

required to conduct performance testing 

at least every five years through title V 

requirements or other state permitting 

requirements. 

The existing rule does not state how 

multiple combustion turbine engines 

that are exhausted through a single 

HRSG would demonstrate compliance 

with the NOX standard. Therefore, we 

are proposing procedures for 

demonstrating compliance when 

multiple combustion turbine engines are 

exhausted through a single HRSG and 

when steam from multiple combustion 

turbine HRSGs is used in a single steam 

turbine. Furthermore, the existing rule 

requires approval from the permitting 

authority for any use of the part 75 NOX

monitoring provisions in lieu of the 

specified part 60 procedures, but we 

concluded that approval is an 

unnecessary burden for facilities only 

using combustion controls. Therefore, 

we are proposing to allow sources using 

only combustion controls to use the 

parametric NOX monitoring in part 75 to 

demonstrate continuous compliance 

without requiring prior approval. 

However, if the source is using post 

combustion control technology to 

comply with the requirements of the 

NSPS, then approval from the 

permitting authority is required prior to 

using the part 75 CEMS calibration 

procedures in place of the part 60 

procedures. 

Finally, for turbine engines replaced 

with an identical overhauled engine as 

part of an exchange program, we are 

proposing that the new turbine undergo 

a new performance test to verify proper 

operation, for owner/operators using 

water or steam to fuel ratio to verify the 

proper ratio, and for owner/operators 

using parametric monitoring to verify 

that the operating parameters are still 

valid. 

G. Additional Request for Comments 

Affected Facility. We are considering 

and requesting comment on amending 

the definition of the affected facility for 

systems with multiple combustion 

turbine engines. Specifically, we are 

requesting comment on treating 

multiple combustion turbine engines 

connected to a single generator, separate 

combustion turbines engines using a 

single HRSG and separate combustion 

turbine engines with separate HRSG that 

use a single steam turbine or otherwise 

combine the useful thermal output as 

single affected facilities. This approach 

would reduce burden to the regulated 

community by simplifying monitoring. 

We are also requesting comment on how 

the applicable emission standards 

would be determined and on how 

‘‘new’’ and ‘‘reconstruction’’ would be 

defined. We are specifically requesting 

comment on basing the emission 

standards on either the base load rating 

of the largest single combustion turbine 

engine or the combined base load 

ratings of the combustion turbine 

engines. For an affected facility with 

multiple combustion turbine engines, 

we are requesting comment on 

considering the entire facility ‘‘new’’ or 

‘‘reconstructed’’ if any combustion 

turbine engine is replaced with a new 

combustion turbine engine or 

reconstructed. 

District Energy. We are considering 

and requesting comment on an 

appropriate method to recognize the 

environmental benefit of district energy 

systems. The steam or hot water 

distribution system of a district energy 

system located in urban areas, college 

and university campuses, hospitals, 

airports and military installations 

eliminates the need for multiple, 

smaller boilers at individual buildings. 

A central facility typically has superior 

emission controls and consists of a few 

larger boilers facilitating more efficient 

operation than numerous separate 

smaller individual boilers. However, 

when the hot water or steam is 

distributed, approximately two to three 

percent of the thermal energy in the 

water and six to nine percent of the 


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thermal energy in the steam is lost, 

reducing the net efficiency advantage. 

We are requesting comment on whether 

it is appropriate to divide the thermal 

output from district energy systems by 

a factor (i.e., 0.95 or 0.90) that would 

account for the net efficiency benefits of 

district energy systems. This approach 

would be similar to the proposed 

approach to how the electric output for 

CHP is considered when determining 

regulatory compliance. We request that 

comments include technical analysis of 

the net benefits in support of any 

conclusions. 

Jet Fuel. We realize that jet fuel is an 

available fuel for combustion turbines 

and are requesting comment on adding 

jet fuel to the definition of distillate oil. 

In the event we include jet fuel in the 

definition of distillate oil, we are also 

requesting the appropriate test method 

(i.e., ASTM method) that should be used 

to identify jet fuel. 

Low-Btu Gases. We are considering 

and requesting comment on amending 

subpart KKKK to specifically exempt 

from the SO2 emission standards 

stationary combustion turbines 

combusting over 50 percent or more per 

calendar month low-Btu gases. Since 

these by-product gases are a recovered 

waste that would otherwise be flared or 

vented rather than a newly supplied 

fossil fuel such as natural gas or fuel oil, 

the combusting of the low-Btu gases in 

a stationary combustion turbine to 

generate electricity does not increase 

SO2 emissions to the atmosphere. Such 

an exemption would encourage the 

environmentally beneficial use of lowBtu by-product gases, and would reduce 

the burden to the owners/operators of 

these affected facilities by eliminating 

the need to demonstrate compliance 

with an SO2 emissions standard. When 

the emissions associated with the 

displaced electric and useful thermal 

output are accounted for, there is a net 

reduction in emissions to the 

atmosphere. 

III. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is, therefore, not 

subject to review under the Executive 

Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011). 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden. The 

amended reconstruction provisions 

would not significantly impact owners/ 

operators of stationary combustion 

turbines within the next 5 years, and the 

other proposed amendments result in no 

changes to the information collection 

requirements of the existing standards 

of performance and would have no 

impact on the information collection 

estimate of projected cost and hour 

burden made and approved by the 

Office of Management and Budget 

(OMB) during the development of the 

existing standards of performance. 

Therefore, the information collection 

requests have not been amended. 

However, OMB previously approved the 

information collection requirements 

contained in the existing regulations (40 

CFR part 60, subpart KKKK) under the 

provisions of the Paperwork Reduction 

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

assigned OMB control number 2060– 

0582. The OMB control numbers for the 

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 proposed 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 proposed rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

The required emissions control 

technology and other requirements have 

not been significantly changed. 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. 

Although this proposed rule will not 

have a significant economic impact on 

a substantial number of small entities, 

the EPA nonetheless has tried to reduce 

the impact of this rule on small entities. 

The proposed amendments would allow 

flexibility in the timing of performance 

testing of idle turbines and fuel 

blending to achieve the SO2 standards. 

We therefore concluded that today’s 

proposed rule would relieve regulatory 

burden for all affected small entities. 

We continue to be interested in the 

potential impacts of the proposed rule 

on small entities and welcome 

comments on issues related to such 

impacts. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This proposed rule does not contain 

a federal mandate that may result in 

expenditures of $100 million or more 

for state, local and tribal governments, 

in the aggregate, or the private sector in 

any 1 year. Since the best system of 

emissions reduction is unchanged and 

there are only minor proposed 

amendments to the performance testing, 

recordkeeping, monitoring and 

reporting requirements, the proposed 

amendments would not significantly 

impact the regulatory burden of this 

rule. Thus, this proposed rule is not 

subject to the requirements of sections 

202 and 205 of UMRA. 

This proposed 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. The 

proposed amendments would reduce 

the overall regulatory requirements of 

the rule. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 


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levels of government, as specified in 

Executive Order 13132. This proposed 

rule 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 action. 

In the spirit of Executive Order 13132, 

and consistent with the EPA policy to 

promote communications between the 

EPA and state and local governments, 

the EPA specifically solicits comment 

on this proposed rule from State and 

local officials. 

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). The EPA is not aware of any 

stationary combustion turbine owned by 

an Indian tribe. Thus, Executive Order 

13175 does not apply to this action. 

The EPA specifically solicits 

additional comment on this proposed 

action from tribal officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

The 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. The 

proposal is not expected to produce 

notable changes in criteria pollutant 

emissions or other pollutants but does 

encourage the current trend towards 

cleaner generation, helping to protect air 

quality and children’s health. The 

agency recognizes that children are 

among the groups most vulnerable to 

climate change impacts and the public 

is invited to submit comments or 

identify peer reviewed studies relevant 

to this proposal based solely on 

technology. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211, (66 FR 28355, May 22, 

2001) because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act (NTTAA) of 1995, Public Law 104– 

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

the EPA to use voluntary consensus 

standards (VCS) in its regulatory 

activities, unless to do so would be 

inconsistent with applicable law or 

otherwise impractical. VCS are 

technical standards (e.g., materials 

specifications, test methods, sampling 

procedures and business practices) that 

are developed or adopted by VCS 

bodies. NTTAA directs the EPA to 

provide Congress, through OMB, 

explanations when the agency decides 

not use available and applicable VCS. 

This proposed rulemaking does not 

involve any new technical standards. 

Therefore, the EPA did not consider the 

use of any VCS. 

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. 

The EPA has determined that this 

proposed rule would not have 

disproportionately high and adverse 

human health or environmental effects 

on minority, low-income or indigenous 

populations because it increases the 

level of environmental protection for all 

affected populations without having any 

disproportionately high adverse human 

health or environmental effects on any 

populations, including any minority, 

low-income or indigenous populations. 

This proposed rule would assure that all 

new stationary combustion turbines 

install appropriate controls to minimize 

health impacts to nearby populations. 

To gain a better understanding of the 

source category and near source 

populations, the EPA conducted a 

demographic analysis on recent 

installations of combustion turbines 

selling >25 MW of power to identify any 

overrepresentation of minority, low 

income, or indigenous populations. This 

analysis only gives some indication of 

the prevalence of sub-populations that 

may be exposed to air pollution from 

the sources; it does not identify the 

demographic characteristics of the most 

highly affected individuals or 

communities, nor does it quantify the 

level of risk faced by those individuals 

or communities. The demographic 

analysis results and the details 

concerning their development are 

presented in the April 20, 2012, 

memorandum titled, Environmental 

Justice Review, a copy of which is 

available in the docket. 

List of Subjects in 40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Incorporation by 

reference, Intergovernmental relations, 

Nitrogen oxides, Reporting and 

recordkeeping requirements, Sulfur 

oxides. 

Dated: June 22, 2012. 

Lisa P. Jackson, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, part 60, of 

the Code of the Federal Regulations is 

proposed to be 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: 

a. By revising paragraph (a)(9); 

b. By revising paragraph (a)(16); 

c. By revising paragraph (a)(18); 

d. By revising paragraph (a)(22); 

e. By revising paragraph (a)(25); 

f. By revising paragraph (a)(40); 

g. By revising paragraph (a)(50); 

h. By revising paragraph (a)(57); 

i. By revising paragraph (a)(59); 

j. By revising paragraph (a)(61); 

k. By revising paragraph (a)(64); 

l. By revising paragraph (a)(68); 

m. By revising paragraph (a)(71); 

n. By revising paragraph (a)(72); 

o. By revising paragraph (a)(75); 

p. By revising paragraph (a)(76); 

q. By revising paragraph (a)(81); 

r. By revising paragraph (a)(88); 

s. By revising paragraph (a)(106); 

t. By revising paragraph (a)(107); 

u. By revising paragraph (a)(108); and 

v. By adding paragraphs (a)(109) 

through (a)(117). 

w. By revising paragraph (h)(4); 

x. By reserving paragraph (i); 

y. By redesignating paragraph (m)(1) 

as paragraph (m)(4); 

z. By revising paragraph (m)(2); 

aa. By adding new paragraphs (m)(1) 

and (m)(3); and 


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bb. By revising newly redesignated 

paragraph (m)(4). 

The revisions and additions read as 

follows. 

§ 60.17 Incorporations by Reference. 

* * * * * 

(a) * * * 

(9) ASTM D129–11, Standard Test 

Method for Sulfur in Petroleum 

Products (General High Pressure 

Decomposition Device Method), IBR 

approved for § 60.4360(c). 

* * * * * 

(16) ASTM D975–11, 11b, Standard 

Specification for Diesel Fuel Oils, IBR 

approved for §§ 60.41b of subpart Db of 

this part, 60.41c of subpart Dc of this 

part, and 60.4420 of subpart KKKK of 

this part. 

* * * * * 

(18) ASTM D1072–06, 06, Standard 

Test Method for Total Sulfur in Fuel 

Gases, IBR approved for § 60.4360(c). 

* * * * * 

(22) ASTM D1266–07, Standard Test 

Method for Sulfur in Petroleum 

Products (Lamp Method), IBR approved 

for § 60.4360(c). 

* * * * * 

(25) ASTM D1552–08, Standard Test 

Method for Sulfur in Petroleum 

Products (High-Temperature Method), 

IBR approved for § 60.4360(c). 

* * * * * 

(40) ASTM D2622–10, Standard Test 

Method for Sulfur in Petroleum 

Products by Wavelength Dispersive XRay Fluorescence Spectrometry, IBR 

approved for § 60.4360(c). 

* * * * * 

(50) ASTM D3246–11, Standard Test 

Method for Sulfur in Petroleum Gas by 

Oxidative Microcoulometry, IBR 

approved for § 60.4360(c). 

* * * * * 

(57) ASTM D4057–06 (Reapproved 

2011), Standard Practice for Manual 

Sampling of Petroleum and Petroleum 

Products, IBR approved for § 60.4360(b). 

* * * * * 

(59) ASTM D4084–07, Standard Test 

Method for Analysis of Hydrogen 

Sulfide in Gaseous Fuels (Lead Acetate 

Reaction Rate Method), IBR approved 

for § 60.4360(c). 

* * * * * 

(61) ASTM D4177–95 (Reapproved 

2010), Standard Practice for Automatic 

Sampling of Petroleum and Petroleum 

Products, IBR approved for § 60.4360(b). 

* * * * * 

(64) ASTM D4294–10, Standard Test 

Method for Sulfur in Petroleum and 

Petroleum Products by EnergyDispersive X-Ray Fluorescence 

Spectrometry, IBR approved for 

§ 60.4360(c). 

* * * * * 

(68) ASTM D4468–85 (Reapproved 

2011), Standard Test Method for Total 

Sulfur in Gaseous Fuels by 

Hydrogenolysis and Rateometric 

Colorimetry, IBR approved for 

§§ 60.335(b) and 60.4360(c). 

* * * * * 

(71) ASTM D4810–88 (Reapproved 

1999), 06, Standard Test Method for 

Hydrogen Sulfide in Natural Gas Using 

Length of Stain Detector Tubes, IBR 

approved for § 60.4360(c). 

(72) ASTM D5287–97 (Reapproved 

2002), 08, Standard Practice for 

Automatic Sampling of Gaseous Fuels, 

IBR approved for § 60.4360(b). 

* * * * * 

(75) ASTM D5453–09, Standard Test 

Method for Determination of Total 

Sulfur in Light Hydrocarbons, Motor 

Fuels and Oils by Ultraviolet 

Fluorescence, IBR approved for 

§ 60.4360(c). 

* * * * * 

(81) ASTM D6228–98 (Reapproved 

2003), 10, Standard Test Method for 

Determination of Sulfur Compounds in 

Natural Gas and Gaseous Fuels by Gas 

Chromatography and Flame Photometric 

Detection, IBR approved for 

§ 60.4360(c). 

* * * * * 

(88) ASTM D6667–10, Standard Test 

Method for Determination of Total 

Volatile Sulfur in Gaseous 

Hydrocarbons and Liquefied Petroleum 

Gases by Ultraviolet Fluorescence, IBR 

approved for § 60.4360(c). 

* * * * * 

(106) ASTM D3699–08, Standard 

Specification for Kerosine, including 

Appendix Xl, (Approved September 1, 

2008), IBR approved for §§ 60.41b of 

subpart Db of this part, 60.41c of 

subpart Dc of this part, and 60.4420 of 

subpart KKKK of this part. 

(107) ASTM D6751–11b, Standard 

Specification for Biodiesel Fuel Blend 

Stock (B100) for Middle Distillate Fuels, 

including Appendices Xl through X3, 

(Approved July 15, 2011), IBR approved 

for §§ 60.41b of subpart Db of this part, 

60.41c of subpart Dc of this part, and 

60.4420 of subpart KKKK of this part. 

(108) ASTM D7467–10, Standard 

Specification for Diesel Fuel Oil, 

Biodiesel Blend (B6 to B20), including 

Appendices Xl through X3, (Approved 

August 1, 2010), IBR approved for 

§§ 60.41b of subpart Db of this part, 

60.41c of subpart Dc of this part, and 

60.4420 of subpart KKKK of this part. 

(109) ASTM D240–09, Standard Test 

Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter, IBR approved for 

§ 60.4360(c). 

(110) ASTM D396–10, Standard 

Specification for Fuel Oils, IBR 

approved for § 60.4420 of subpart KKKK 

of this part. 

(111) ASTM D1826–94 (Reapproved 

2010), Standard Test Method for 

Calorific (Heating) Value of Gases in 

Natural Gas Range by Continuous 

Recording Calorimeter, IBR approved 

for § 60.4350(c). 

(112) ASTM D3588–98 (Reapproved 

2003) Standard Practice for Calculating 

Heat Value, Compressibility Factor, and 

Relative Density of Gaseous Fuels, IBR 

approved for § 60.4360(c). 

(113) ASTM D4809–09a, Standard 

Test Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter (Precision Method), IBR 

approved for § 60.4360(c). 

(114) ASTM D4891–89 (Reapproved 

2006), Standard Test Method for 

Heating Value of Gases in Natural Gas 

Range by Stoichiometric Combustion, 

IBR approved for § 60.4360(c). 

(115) ASTM D5504–08, Standard Test 

Method for Determination of Sulfur 

Compounds in Natural Gas and Gaseous 

Fuels by Gas Chromatography and 

Chemiluminescence, IBR approved for 

§ 60.4360(c). 

(116) ASTM D6522–11, Standard Test 

Method for Determination of Nitrogen 

Oxides, Carbon Monoxide, and Oxygen 

Concentrations in Emissions from 

Natural Gas-Fired Reciprocating 

Engines, Combustion Turbines, Boilers, 

and Process Heaters Using Portable 

Analyzers, IBR approved for 

§ 60.4400(a). 

(117) ASTM D7164–05, 10, Standard 

Practice for On-line/At-line Heating 

Value Determination of Gaseous Fuels 

by Gas Chromatography, IBR approved 

for § 60.4360(c). 

* * * * * 

(h) * * * 

(4) ANSI/ASME PTC 19.10–1981, 

Flue and Exhaust Gas Analyses [Part 10, 

Instruments and Apparatus], (Issued 

August 31, 1981), IBR approved for 

§ 60.56c(b), § 60.63(f), § 60.106(e), 

§ 60.104a(d), (h), (i), and (j), 

§ 60.105a(d), (f), and (g), § 60.106a(a), 

§ 60.107a(a), (c), and (d), tables 1 and 3 

of subpart EEEE, tables 2 and 4 of 

subpart FFFF, table 2 of subpart JJJJ, 

§ 60.4415(b), § 60.2145 and (t), 

§ 60.2710(s), (t) and (w), 60.2730(q), 

60.4900(b), 60.5220(b), tables 1 and 2 to 

subpart LLLL, and tables 2 and 3 to 

subpart MMMM. 

* * * * * 

(i) [Reserved] 

* * * * * 


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52564 Federal Register / Vol. 77, No. 168 / Wednesday, August 29, 2012 / Proposed Rules 

(m) * * * 

(1) Gas Processors Association 

Method 2166–05, Obtaining Natural Gas 

Samples for Analysis by Gas 

Chromatography, IBR approved for 

§ 60.4360(b). 

(2) Gas Processors Association 

Method 2172–09, Calculation of Gross 

Heating Value, Relative Density, 

Compressibility, and Theoretical 

Hydrocarbon Liquid Content for Natural 

Gas Mixtures for Custody Transfer, IBR 

approved for § 60.4360(c). 

(3) Gas Processors Association 

Method 2174–93, Obtaining Liquid 

Hydrocarbon Samples for Analysis by 

Gas Chromatography, IBR approved for 

§ 60.4360(b). 

(4) Gas Processors Association 

Standard 2377–86, Test for Hydrogen 

Sulfide and Carbon Dioxide in Natural 

Gas Using Length of Stain Tubes, IBR 

approved for §§ 60.105(b), 60.107a(b), 

60.334(h), and 60.4360(c). 

* * * * * 

Subpart GG—[Amended] 

3. Section 60.330 is amended by 

revising paragraph (a) and adding 

paragraph (c) to read as follows: 

§ 60.330 Applicability and designation of 

affected facility. 

(a) The provisions of this subpart are 

applicable to the following affected 

facilities: All stationary gas turbines not 

covered by subparts Da or KKKK of this 

part with a heat input at peak load equal 

to or greater than 10.7 gigajoules (10 

million Btu) per hour, based on the 

lower heating value of the fuel fired. 

* * * * * 

(c) As an alternative to meeting the 

requirements of this subpart, an owner 

or operator can petition the 

Administrator (in writing) to comply 

with the requirements for modified 

units in subpart KKKK 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 for modified units in 

subpart KKKK of this part. 

(d) If you are an owner or operator of 

a non-major source subject to this 

subpart, you are exempt from the 

obligation to obtain a permit under 40 

CFR part 70 or 40 CFR part 71, provided 

you are not required to obtain a permit 

under 40 CFR 70.3(a) or 40 CFR 71.3(a) 

for a reason other than your status as a 

non-major source under this subpart. 

Notwithstanding the previous sentence, 

you must continue to comply with the 

provisions of this subpart, as applicable. 

Subpart KKKK—Standards of 

Performance for Stationary 

Combustion Turbines 

4. Part 60 is amended by revising 

subpart KKKK to read as follows: 

Introduction 

60.4300 What is the purpose of this 

subpart? 

Applicability 

60.4305 Does this subpart apply to my 

stationary combustion turbine? 

60.4310 What stationary combustion 

turbines are not subject to this subpart? 

Emission Standards 

60.4315 What pollutants are regulated by 

this subpart? 

60.4320 What NOX emissions standard 

must I meet? 

60.4330 What SO2 emissions standard must 

I meet? 

General Compliance Requirements 

60.4333 What are my general requirements 

for complying with this subpart? 

60.4334 Affirmative Defense for Violation 

of Emission Standards During 

Malfunction. 

Monitoring 

60.4335 How do I demonstrate compliance 

with my NOX emissions standard 

without using a NOX CEMS if I use water 

or steam injection? 

60.4340 How do I demonstrate compliance 

with my NOX emissions standard 

without using a NOX CEMS if I do not 

use water or steam injection? 

60.4342 How do I monitor NOX control 

operating parameters? 

60.4345 How do I demonstrate compliance 

with my NOX emissions standard using 

a NOX CEMS? 

60.4350 How do I use the NOX CEMS data 

to determine excess emissions? 

60.4360 How do I use fuel sulfur analysis 

to determine the total sulfur content of 

the fuel combusted in my stationary 

combustion turbine? 

60.4365 How frequently must I determine 

the fuel sulfur content? 

60.4370 How do I demonstrate compliance 

with my SO2 emissions standard using 

records of the fuel sulfur content? 

60.4372 How do I demonstrate compliance 

with my SO2 emissions standard and 

determine excess emissions using a SO2

CEMS? 

Recordkeeping and Reporting 

60.4375 What reports must I submit? 

60.4380 How are NOX excess emissions 

and monitor downtime reported? 

60.4385 How are SO2 excess emissions and 

monitor downtime reported? 

60.4390 What records must I maintain? 

60.4395 When must I submit my reports? 

Performance Tests 

60.4400 How do I conduct performance 

tests to demonstrate compliance with my 

NOX emissions standard if I do not have 

a NOX CEMS? 

60.4405 How do I conduct a performance 

test if I use a NOX CEMS? 

60.4415 How do I conduct performance 

tests to demonstrate compliance with my 

SO2 emissions standard? 

Definitions 

60.4420 What definitions apply to this 

subpart? 

Table 1 to Subpart KKKK of Part 60— 

Nitrogen Oxide Emission Standards for 

Stationary Combustion Turbines 

Subpart KKKK—Standards of 

Performance for Stationary 

Combustion Turbines 

Introduction 

§ 60.4300 What is the purpose of this 

subpart? 

This subpart establishes emission 

standards and compliance schedules for 

the control of emissions from stationary 

combustion turbines that commenced 

construction, modification, or 

reconstruction after February 18, 2005. 

Applicability 

§ 60.4305 Does this subpart apply to my 

stationary combustion turbine? 

(a) You are subject to this subpart if 

you own or operate a stationary 

combustion turbine that commenced 

construction, modification, or 

reconstruction after February 18, 2005, 

and that has a base load rating equal to 

or greater than 2.9 megawatts (MW) (10 

million British thermal units per hour 

(MMBtu/h)), except as provided for in 

§ 60.4310. Any additional heat input 

from duct burners used with heat 

recovery steam generating units or fuel 

preheaters is not included in the heat 

input value used to determine the 

applicability of this subpart to a given 

stationary combustion turbine. 

(b) For the purpose of this subpart, 

only the combustion turbine engine 

itself is used to determine whether the 

affected facility is new or reconstructed. 

Other equipment included in the 

definition of a stationary combustion 

turbine is not included when 

determining if a facility is new or 

reconstructed. 

(c) A combustion turbine engine 

subject to this subpart is not subject to 

subpart GG of this part. 

(d) Duct burners that do not burn any 

solid fuels when used with a heat 

recovery steam generating unit that is 

part of either a combined cycle 

combustion turbine or a combined heat 

and power (CHP) combustion turbine 

subject to this subpart are not subject to 

subpart D, Da, Db, or Dc of this part, as 

applicable. 

(e) If you own or operate either a 

stationary combustion turbine 


TKELLEY on DSK3SPTVN1PROD with PROPOSALS
Federal Register / Vol. 77, No. 168 / Wednesday, August 29, 2012 / Proposed Rules 52565 

(including a combined cycle 

combustion turbine or a CHP 

combustion turbine) that commenced 

construction, modification, or 

reconstruction on or before February 18, 

2005, you may submit a written petition 

to the Administrator requesting that the 

stationary combustion turbine be 

allowed to comply with the applicable 

requirements for modified units under 

this subpart as an alternative to 

complying with subpart GG of this part, 

and with subparts D, Da, Db, and Dc of 

this part, as applicable. If the 

Administrator or delegated authority 

approves the petitioner’s request, the 

affected facility must comply with the 

requirements for modified units under 

this subpart unless the combustion 

turbine engine is reconstructed or 

replaced with a new facility in the 

future. 

(f) If you are an owner or operator of 

a non-major source subject to this 

subpart, you are exempt from the 

obligation to obtain a permit under 40 

CFR part 70 or 40 CFR part 71, provided 

you are not required to obtain a permit 

under 40 CFR 70.3(a) or 40 CFR 71.3(a) 

for a reason other than your status as a 

non-major source under this subpart. 

Notwithstanding the previous sentence, 

you must continue to comply with the 

provisions of this subpart, as applicable. 

§ 60.4310 What stationary combustion 

turbines are not subject to this subpart? 

(a) An integrated gasification 

combined cycle electric utility steam 

generating unit subject to subpart Da of 

this part is not subject to this subpart. 

(b) A stationary combustion turbine 

used in a combustion turbine test cell/ 

stand as defined in § 60.4420 is not 

subject to this subpart. 

(c) A stationary combustion turbine 

subject to subpart Ea, subpart Eb, or 

subpart AAAA of this part is not subject 

to this subpart. 

(d) A stationary combustion turbine 

subject to an EPA approved State or 

Federal plan implementing under 

authority of Clean Air Act sections 

111(d)/129 either subpart Cb or subpart 

BBBB of this part is not subject to this 

subpart. 

Emission Standards 

§ 60.4315 What pollutants are regulated by 

this subpart? 

The pollutants regulated by this 

subpart are nitrogen oxides (NOX) and 

sulfur dioxide (SO2). 

§ 60.4320 What NOX emissions standard 

must I meet? 

(a) For each simple cycle stationary 

combustion turbine, except as provided 

for in paragraph (d) of this section, you 

must not discharge into the atmosphere 

from the affected facility any gases that 

contain NOX in excess of the applicable 

emissions standard as determined on a 

4-operating hour basis and according to 

the requirements specified in paragraph 

(c) of this section. 

(b) For each combined-cycle 

combustion turbine or CHP combustion 

turbine except as provided for in 

paragraph (d) of this section, you must 

not discharge into the atmosphere from 

the affected facility any gases that 

contain NOX into the atmosphere from 

the affected facility in excess of the 

applicable emissions standard on a 30- 

operating day basis and according to the 

requirements specified in paragraph (c) 

of this section. 

(c) For the purpose of determining 

compliance with the applicable 

emissions standard in paragraphs (a) 

and (b) of this section, you must meet 

the requirements specified in 

paragraphs (c)(1) through (c)(4), as 

applicable to your affected facility. 

(1) The NOX emissions standard that 

is applicable to your affected facility 

shall be determined on an operating 

hour basis except as provided for in 

paragraph (c)(2) of this section. 

Determining the hourly NOX emission 

standards for your affected facility 

requires recording hourly data and 

maintaining records according to the 

requirements in § 60.4390. 

(2) As an alternative to the 

requirements specified in paragraph 

(c)(1) of this section, you may elect to 

use the lowest emissions standard 

determined using Table 1 of this subpart 

that is applicable to your affected 

facility for the entire required 

compliance period. 

(3) During each operating hour when 

only natural gas is combusted in the 

combustion turbine engine, you must 

meet the applicable NOX emissions 

standard determined using Table 1 of 

this subpart for a stationary combustion 

firing natural gas. During each operating 

hour when any fuel other than natural 

gas is combusted in the combustion 

turbine engine, you must meet the 

applicable NOX emissions standard 

determined using Table 1 of this subpart 

for a stationary combustion firing fuels 

other than natural gas. If multiple fuels 

are combusted during a given operating 

hour, then the highest applicable NOX

emissions standard is applied for the 

entire operating hour. 

(4) If you have two or more 

combustion turbine engines connected 

to a single electric generator, each of the 

combustion turbine engines must meet 

the applicable NOX emissions standard 

determined using Table 1 of this 

subpart. 

(d) Stationary combustion turbines 

specified in paragraphs (d)(1) through 

(3) of this section are exempt from the 

applicable NOX emissions standard in 

paragraphs (a) and (b) of this section. 

(1) An emergency combustion turbine, 

as defined in § 60.4420; 

(2) A stationary combustion turbine 

used for research and development of 

equipment for combustion turbine 

emissions control techniques or 

efficiency improvements as determined 

by the Administrator or delegated 

authority on a case-by-case basis; and 

(3) A stationary combustion turbine 

that combusts byproduct fuels for which 

a facility-specific NOX emissions 

standard has been established by the 

Administrator according to the 

requirements of paragraphs (d)(3)(i) and 

(ii). 

(i) You may request a facility-specific 

NOX emissions standard by submitting 

a written request to the Administrator or 

delegated authority explaining why 

your affected facility when burning the 

byproduct fuel is unable to comply with 

the applicable NOX emissions standard 

determined using Table 1 of this 

subpart. 

(ii) If the Administrator approves the 

request, a letter will be sent to the 

facility describing the facility-specific 

NOX emissions standard. You must use 

the compliance procedures detailed in 

the letter and make the letter available 

to the public. If the Administrator 

determines it is appropriate, the 

conditions and requirements of the 

letter can be reviewed and changed at 

any point. 

(e) For affected facilities for which 

construction, modification, or 

reconstruction commenced before 

August 30, 2012, you must meet the 

NOX emissions standard applicable 

under this section to your affected 

facility during all times when the 

affected facility is operating except 

during periods of startup, shutdown, or 

malfunction. For each affected facility 

for which construction, reconstruction, 

or modification commenced after 

August 29, 2012, you must meet the 

NOX emissions standard applicable 

under this section to your affected 

facility during all times when the 

affected facility is operating (including 

periods of startup, shutdown, and 

malfunction). 

§ 60.4330 What SO2 emissions standard 

must I meet? 

(a) For each stationary combustion 

turbine, except as provided for in 

paragraphs (b) through (g) of this 

section, you must not cause to be 

discharged into the atmosphere from the 


TKELLEY on DSK3SPTVN1PROD with PROPOSALS
52566 Federal Register / Vol. 77, No. 168 / Wednesday, August 29, 2012 / Proposed Rules 

affected facility any gases that contain 

SO2 in excess of either: 

(1) 110 nanograms per Joule (ng/J) 

(0.90 pounds per megawatt-hour (lb/ 

MWh)) gross energy output; or 

(2) 26 ng SO2/J (0.060 lb SO2/MMBtu) 

heat input. 

(b) As an alternative to the 

requirements of paragraph (a) of this 

section, for each stationary combustion 

turbine combusting 50 percent or more 

low-Btu gas per calendar month based 

on total heat input using the higher 

heating value of the fuel, you may limit 

the sulfur content of the fuel to no more 

than either: 

(1) 650 milligrams of sulfur per 

standard cubic meter (mg/scm) (28 

grains (gr) of sulfur per 100 standard 

cubic feet (scf)); or 

(2) 65 ng SO2/J (0.15 lb SO2/MMBtu) 

heat input. 

(c) For each stationary combustion 

turbine located in a noncontinental area, 

you must not cause to be discharged 

into the atmosphere from the affected 

facility any gases that contains SO2 in 

excess of either: 

(1) 780 ng/J (6.2 lb/MWh) gross energy 

output; or 

(2) 180 ng SO2/J (0.42 lb SO2/MMBtu) 

heat input. 

(d) For each stationary combustion 

turbine for which the Administrator 

determines that the affected facility does 

not have access to natural gas and the 

removal of sulfur compounds from the 

fuel would cause more environmental 

harm than benefit, you must not cause 

to be discharged into the atmosphere 

from the affected facility any gases that 

contain SO2 in excess of either: 

(1) 780 ng/J (6.2 lb/MWh) gross energy 

output; or 

(2) 180 ng SO2/J (0.42 lb SO2/MMBtu) 

heat input. 

(e) A stationary combustion turbine 

that is subject to SO2 emission standards 

under either subpart J or Ja of this part 

is not subject to the SO2 emission 

standards in this subpart. 

(f) A combustion turbine that is 

subject to a federally enforceable 

requirement limiting the sulfur content 

of gaseous fuels combusted in the 

stationary combustion turbine to no 

more than 460 mg/scm (20 gr/100 scf) 

and/or for liquid fuels no more than 

0.050 weight percent sulfur is not 

subject to the SO2 emission standards in 

this subpart. 

(g) For affected facilities for which 

construction, modification, or 

reconstruction commenced before 

August 30, 2012, you must meet the SO2

emissions standard applicable under 

this section to your affected facility 

during all times when the affected 

facility is operating except during 

periods of startup, shutdown, or 

malfunction. For each affected facility 

for which construction, reconstruction, 

or modification commenced after 

August 29, 2012, you must meet the SO2

emissions standard applicable under 

this section to your affected facility 

during all times when the affected 

facility is operating (including periods 

of startup, shutdown and malfunction). 

General Compliance Requirements 

§ 60.4333 What are my general 

requirements for complying with this 

subpart? 

(a) You must operate and maintain 

your stationary combustion turbine, air 

pollution control equipment, and 

monitoring equipment in a manner 

consistent with good air pollution 

control practices for minimizing 

emissions at all times including during 

startup, shutdown, and malfunction. 

(b) If you own or operate a stationary 

combustion turbine subject to a NOX

emissions standard in § 60.4320, you 

must conduct an initial performance test 

according to § 60.8 using the applicable 

methods in § 60.4400 or § 60.4405. 

Thereafter, unless you perform 

continuous monitoring consistent with 

§§ 60.4335, 60.4340(b), or 60.4345, you 

must conduct subsequent performance 

tests according to the applicable 

requirements in paragraphs (b)(1) 

through (b)(6) of this section. 

(1) Except as provided for in 

paragraphs (b)(2) through (b)(5) of this 

section, you must conduct subsequent 

performance tests within 12 calendar 

months following the date the previous 

performance test was required to be 

conducted. Performance tests must be 

separated by a minimum of 9 calendar 

months. 

(2) If the NOX emission result from 

the most recent performance test is less 

than or equal to 75 percent of the NOX

emissions standard for the stationary 

combustion turbine, you may reduce the 

frequency of subsequent performance 

tests to 24 calendar months following 

the date the previous performance test 

was required to be conducted. 

Performance tests must be separated by 

a minimum of 21 calendar months. If 

the results of any subsequent 

performance test exceed 75 percent of 

the NOX emissions standard for the 

stationary combustion turbine, you must 

resume annual performance testing. 

(3) An affected facility that has not 

operated for the 60 calendar days prior 

to the due date of a performance test is 

not required to perform the subsequent 

performance test until 45 calendar days 

after the next operating day. The 

delegated permitting authority must be 

notified of recommencement of 

operation consistent with § 60.4375(d). 

(4) If you own or operate an affected 

facility that has operated 50 operating 

hours or less in total or with a particular 

fuel since the date the previous 

performance test was required to be 

conducted you may request an 

extension from the otherwise required 

performance test until after the affected 

facility has operated more than 50 

operating hours in total or with a 

particular fuel since the date of the 

previous performance test was required 

to be conducted. A request for an 

extension under this paragraph must be 

addressed to the relevant air division or 

office director of the appropriate 

Regional Office of the U.S. EPA as 

identified in § 60.4(a) for his or her 

approval at least 30 calendar days prior 

to the date on which the performance 

test is required to be conducted. If an 

exemption is approved, a performance 

test must be conducted within 45 

calendar days after the day the facility 

reaches 50 hours of operation since the 

date the previous performance test was 

required to be conducted. When the 

facility has operated more than 50 

operating hours since the date the 

previous performance test was required 

to be conducted, the delegated 

permitting authority must be notified 

consistent with § 60.4375(e). 

(5) For a facility at which a group 

consisting of no more than five similar 

stationary combustion turbines (i.e., 

same manufacturer and model number) 

is operated, you may request the use of 

a custom testing schedule by submitting 

a written request to the Administrator or 

delegated authority. The minimum 

requirements of the custom schedule 

include the conditions specified in 

paragraphs (5)(i) through (v) of this 

section. 

(i) Emissions from the most recent 

performance test for each individual 

affected facility are 75 percent or less of 

the applicable standard; 

(ii) Each stationary combustion 

turbine uses the same emissions control 

technology; 

(iii) Each stationary combustion 

turbine is operated in a similar manner; 

(iv) Each stationary combustion 

turbine and its emissions control 

equipment are maintained according to 

the manufacturer’s recommended 

maintenance procedures; and 

(v) A performance test is conducted 

on each affected facility at least once 

every 5 calendar years. 

(6) A stationary combustion turbine 

subject to a NOX emissions standard in 

§ 60.4320 that exchanges the 

combustion turbine engine for an 

overhauled combustion turbine engine 


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as part of an exchange program, must 

conduct an initial performance test 

according to § 60.8 using the applicable 

methods in § 60.4400. 

(c) Except as provided for in 

paragraphs (c)(1) or (2) of this section, 

for each stationary combustion turbine 

subject to a NOX emissions standard in 

§ 60.4320, you must demonstrate 

continuous compliance using a 

continuous emissions monitoring 

system (CEMS) for measuring NOX

emissions according to the provisions in 

§ 60.4345. If your stationary combustion 

turbine is equipped with a NOX CEMS, 

those measurements must be used to 

determine excess emissions. 

(1) If your stationary combustion 

turbine uses water or steam injection 

but not post-combustion controls to 

meet the applicable NOX emissions 

standard in § 60.4320, you may elect to 

demonstrate continuous compliance 

using either the pounds per million 

British thermal units (lb/MMBtu) or the 

part per million (ppm) standard 

according to the provisions in § 60.4335. 

(2) If your stationary combustion 

turbine does not use water injection, 

steam injection, or post-combustion 

controls to meet the applicable NOX

emissions standard in § 60.4320, you 

may elect to demonstrate continuous 

compliance with either the lb/MMBtu or 

ppm standard according to the 

provisions in § 60.4340. 

(d) An owner or operator of a 

stationary combustion turbine subject to 

an SO2 emissions standard in § 60.4330 

must demonstrate compliance using one 

of the methods specified in paragraphs 

(d)(1) through (4) of this section. 

(1) Conduct an initial performance 

test according to § 60.8 and use the 

applicable methods in § 60.4415. 

Thereafter, you must conduct 

subsequent performance tests within 12 

calendar months following the date the 

previous performance test was required 

to be conducted. Performance tests must 

be separated by a minimum of 9 

calendar months. An affected facility 

that has not operated for the 60 calendar 

days prior to the due date of a 

performance test is not required to 

perform the subsequent performance 

test until 45 calendar days after the next 

operating day; 

(2) Conduct an initial performance 

test according to § 60.8 and use the 

applicable methods in § 60.4415. 

Thereafter, conduct subsequent fuel 

sulfur analyses using the applicable 

methods specified in § 60.4360 and at 

the frequency specified in § 60.4365; 

(3) Conduct an initial performance 

test according to § 60.8 and use the 

applicable methods in § 60.4415. 

Thereafter, maintain records (such as a 

current, valid purchase contract, tariff 

sheet, or transportation contract) 

documenting that total sulfur content 

for the initial and subsequent fuel 

combusted in your stationary 

combustion turbine at all times does not 

exceed applicable conditions specified 

in § 60.4370; or 

(4) Conduct an initial performance 

test according to § 60.8 using the 

applicable methods in § 60.4415. 

Thereafter, continue to monitor SO2

emissions using a CEMS according to 

the requirements specified in § 60.4372. 

(e) If you elect to comply with an 

input-based standard (lb/MMBtu) and 

your affected facility includes use of one 

or more heat recovery steam generating 

units, then you must determine 

compliance with the applicable NOX

and SO2 emission standards according 

to the procedures specified in 

paragraphs (e)(1) or (2) of this section as 

applicable to the heat recovery steam 

generating unit configuration used for 

your affected facility. 

(1) For a configuration where a single 

combustion turbine engine is exhausted 

through the heat recovery steam 

generating unit, you must measure both 

the emissions at the exhaust stack for 

the heat recovery steam generating unit 

and the fuel flow to the combustion 

turbine engine and any associated duct 

burners. 

(2) For a configuration where two or 

more combustion turbine engines are 

exhausted through a heat recovery 

steam generating unit, you must 

measure both the total emissions at the 

exhaust stack for the heat recovery 

steam generating unit and the total fuel 

flow to each combustion turbine engine 

and any associated duct burners. The 

applicable emissions standard for the 

affected facility is equal to the most 

stringent emissions standard for any 

individual combustion turbine engine. 

(f) If you elect to comply with an 

output-based standard (lb/MWh) and 

your affected facility includes use of one 

or more heat recovery steam generating 

units, then you must determine 

compliance with the applicable NOX

and SO2 emission standards according 

to the procedures in paragraphs (f)(1), 

(2), or (3) of this section as applicable 

to the heat recovery steam generating 

unit configuration used for your affected 

facility. 

(1) For a configuration where a single 

combustion turbine engine is exhausted 

through the heat recovery steam 

generating unit, you must measure both 

the emissions at the exhaust stack for 

the heat recovery steam generating unit 

and the total electrical, mechanical 

energy, and useful thermal output of the 

stationary combustion turbine (as 

applicable). 

(2) For a configuration where two or 

more combustion turbine engines are 

exhausted through a single heat 

recovery steam generating unit, you 

must measure both the total emissions 

at the exhaust stack for the heat 

recovery steam generating unit, and the 

total electrical, mechanical energy, and 

useful thermal output of the heat 

recovery steam generating unit and each 

combustion turbine engine (as 

applicable). The applicable emissions 

standard for the affected facility is equal 

to the most stringent emissions standard 

for any individual combustion turbine 

engines. 

(3) For a configuration where your 

combustion turbine engines are 

exhausted through two or more heat 

recovery steam generating units which 

serve a common steam turbine or steam 

header, you must measure both the 

emissions at the exhaust stack for each 

heat recovery steam generating unit and 

the total electrical or mechanical energy 

output of each combustion turbine 

engine (as applicable). To determine the 

gross energy output of the steam 

produced by the heat recovery steam 

generating unit, you must develop a 

custom method and provide 

information, satisfactory to the 

Administrator or delegated authority, 

apportioning the gross energy output of 

the steam produced by the heat recovery 

steam generating units to each of the 

affected stationary combustion turbines. 

§ 60.4334 Affirmative Defense for Violation 

of Emission Standards During Malfunction. 

In response to an action to enforce the 

standards set forth in paragraphs 

§§ 60.4320 and 60.4330 you may assert 

an affirmative defense to a claim for 

civil penalties for violations of such 

standards that are caused by 

malfunction, as defined at 40 CFR 60.2. 

Appropriate penalties may be assessed; 

however, if you fail to meet your burden 

of proving all of the requirements in the 

affirmative defense, the affirmative 

defense shall not be available for claims 

for injunctive relief. 

(a) To establish the affirmative 

defense in any action to enforce such a 

standard, you must timely meet the 

reporting requirements in paragraph (b) 

of this section, and must prove by a 

preponderance of evidence that: 

(1) The violation: 

(i) Was caused by a sudden, 

infrequent, and unavoidable failure of 

air pollution control equipment, process 

equipment, or a process to operate in a 

normal or usual manner, and 

(ii) Could not have been prevented 

through careful planning, proper design 


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or better operation and maintenance 

practices; and 

(iii) Did not stem from any activity or 

event that could have been foreseen and 

avoided, or planned for; and 

(iv) Was not part of a recurring pattern 

indicative of inadequate design, 

operation, or maintenance; and 

(2) Repairs were made as 

expeditiously as possible when a 

violation occurred. Off-shift and 

overtime labor were used, to the extent 

practicable to make these repairs; and 

(3) The frequency, amount and 

duration of the violation (including any 

bypass) were minimized to the 

maximum extent practicable; and 

(4) If the violation resulted from a 

bypass of control equipment or a 

process, then the bypass was 

unavoidable to prevent loss of life, 

personal injury, or severe property 

damage; and 

(5) All possible steps were taken to 

minimize the impact of the violation on 

ambient air quality, the environment, 

and human health; and 

(6) All emissions monitoring and 

control systems were kept in operation 

if at all possible, consistent with safety 

and good air pollution control practices; 

and 

(7) All of the actions in response to 

the violation were documented by 

properly signed, contemporaneous 

operating logs; and 

(8) At all times, the affected source 

was operated in a manner consistent 

with good practices for minimizing 

emissions; and 

(9) A written root cause analysis has 

been prepared, the purpose of which is 

to determine, correct, and eliminate the 

primary causes of the malfunction and 

the violation resulting from the 

malfunction event at issue. The analysis 

must also specify, using best monitoring 

methods and engineering judgment, the 

amount of any emissions that were the 

result of the malfunction. 

(b) Report. The owner or operator 

seeking to assert an affirmative defense 

shall submit a written report to the 

Administrator or delegated authority 

with all necessary supporting 

documentation, that it has met the 

requirements set forth in paragraph (a) 

of this section. This affirmative defense 

report shall be included in the first 

periodic compliance, deviation report or 

excess emission report otherwise 

required after the initial occurrence of 

the violation of the relevant standard 

(which may be the end of any applicable 

averaging period). If such compliance, 

deviation report or excess emission 

report is due less than 45 days after the 

initial occurrence of the violation, the 

affirmative defense report may be 

included in the second compliance, 

deviation report, or excess emission 

report due after the initial occurrence of 

the violation of the relevant standard. 

Monitoring 

§ 60.4335 How do I demonstrate 

compliance with my NOX emissions 

standard without using a NOX CEMS if I use 

water or steam injection? 

If you qualify and elect to 

demonstrate continuous compliance 

according to the provisions of 

§ 60.4333(c)(1), you must install, 

calibrate, maintain, and operate a 

continuous monitoring system to 

monitor and record the fuel 

consumption and the ratio of water or 

steam to fuel fired in the combustion 

turbine engine consistent with the 

requirements in § 60.4342. Water or 

steam only needs to be injected when a 

fuel is being combusted that requires 

water or steam injection for compliance 

with the applicable NOX emissions 

standard. 

§ 60.4340 How do I demonstrate 

compliance with my NOX emissions 

standard without using a NOX CEMS if I do 

not use water or steam injection? 

(a) If you qualify and elect to 

demonstrate continuous compliance 

according to the provisions of 

§ 60.4333(c)(2), you must demonstrate 

compliance with the NOX emissions 

standard using the methods specified in 

either paragraphs (a)(1) through (3) of 

this section. 

(1) Conduct performance tests 

according to requirements in § 60.4400; 

(2) Monitor the NOX emissions rate 

using the methodology in appendix E to 

part 75 of this chapter, or the low mass 

emissions methodology in § 75.19; or 

(3) Install, calibrate, maintain and 

operate an operating parameter 

continuous monitoring system 

according to the requirements specified 

in paragraph (b) of this section and 

consistent with the requirements 

specified in § 60.4342. 

(b) Continuous operating parameter 

monitoring must be performed using the 

methods specified in paragraphs (b)(1) 

through (4) of this section as applicable 

to the stationary combustion turbine. 

(1) Selection of the operating 

parameters used to comply with this 

paragraph must be identified in the 

performance test report, and are subject 

to the review and approval of the 

delegated permitting authority. 

(2) For a lean premix stationary 

combustion turbine, you must 

continuously monitor the appropriate 

parameters to determine whether the 

unit is operating in low-NOX mode 

when low-NOX operation is required to 

comply with the applicable emission 

NOX standard. 

(3) For a stationary combustion 

turbine other than a lean premix 

stationary combustion turbine, you must 

define parameters indicative of the 

unit’s NOX formation characteristics, 

and monitor these parameters 

continuously. 

(4) You must perform the parametric 

monitoring described in section 2.3 in 

appendix E to part 75 of this chapter or 

in § 75.19(c)(1)(iv)(H). 

§ 60.4342 How do I monitor NOX control 

operating parameters? 

(a) If you monitor steam or water to 

fuel ratio according to § 60.4335 or other 

parameters according to § 60.4340, the 

applicable parameters must be 

continuously monitored and recorded 

during the performance test, to establish 

acceptable values and ranges. You may 

supplement the performance test data 

with engineering analyses, design 

specifications, manufacturer’s 

recommendations, and other relevant 

information to define the acceptable 

parametric ranges more precisely. You 

must develop and keep on-site a 

parameter monitoring plan which 

explains the procedures used to 

document proper operation of the NOX

emission controls. The plan must 

include the information specified in 

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

section: 

(1) Identification of the parameters to 

be monitored and show there is a 

significant relationship to emissions and 

proper operation of the NOX emission 

controls; 

(2) Selected parameter ranges (or 

designated conditions) indicative of 

proper operation of the stationary 

combustion turbine NOX emission 

controls, or describe the process by 

which such range (or designated 

condition) will be established; 

(3) Explanation of the process you 

will use to make certain that you obtain 

data that are representative of the 

emissions or parameters being 

monitored (such as detector location, 

installation specification if applicable); 

(4) Description of quality assurance 

and control practices used to ensure the 

continuing validity of the data; 

(5) Description of the frequency of 

monitoring and the data collection 

procedures which you will use (e.g., you 

are using a computerized data 

acquisition over a number of discrete 

data points with the average (or 

maximum value) being used for 

purposes of determining whether an 

exceedance has occurred); and 

(6) Justification for the proposed 

elements of the monitoring. If a 


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proposed performance specification 

differs from manufacturer 

recommendation, you must explain the 

reasons for the differences. You must 

submit the data supporting the 

justification, but you may refer to 

generally available sources of 

information used to support the 

justification. You may rely on 

engineering assessments and other data, 

provided you demonstrate factors which 

assure compliance or explain why 

performance testing is unnecessary to 

establish indicator ranges. 

(b) The ratio of water or steam to fuel 

and parameter continuous monitoring 

system ranges must be reestablished at 

least 60 calendar months following the 

previous calibration and each time the 

combustion turbine engine is replaced 

with an overhauled turbine engine as 

part of an exchange program. An 

affected facility that has not operated for 

60 calendar days prior to the due date 

of a recalibration you are not required 

to perform the subsequent recalibration 

until 45 calendar days after the next 

operating day. 

§ 60.4345 How do I demonstrate 

compliance with my NOX emissions 

standard using a NOX CEMS? 

(a) Each CEMS measuring NOX

emissions used to meet the 

requirements of this subpart, must meet 

the requirements in paragraphs (a)(1) 

through (7) of this section. 

(1) You must install, certify, maintain, 

and operate a NOX monitor to determine 

the hourly average NOX emissions in the 

units of the standard with which you 

are complying; 

(2) If you elect to comply with the 

ppm emissions standard, you must also 

install a diluent gas (oxygen (O2) or 

carbon dioxide (CO2)) monitor; 

(3) If you elect to comply with an 

input-based emissions standard, you 

must install, calibrate, maintain, and 

operate either a fuel flow meter (or flow 

meters) or an O2 or CO2 CEMS and a 

stack flow meter to continuously 

measure the heat input to the affected 

facility; 

(4) If you elect to comply with an 

output-based emissions standard, you 

must also install, calibrate, maintain, 

and operate both a watt meter (or 

meters) to continuously measure the 

gross electrical output from the affected 

facility and a stack flow meter. If you 

have a CHP combustion turbine and 

elect to comply with an output-based 

emissions standard, you must also 

install, calibrate, maintain, and operate 

meters to continuously determine the 

total useful recovered thermal energy. 

For steam this includes flow rate, 

temperature, and pressure. If you have 

a direct mechanical dive application 

and elect to comply with the outputbased emissions standard you must 

submit a plan to the Administrator or 

delegated authority for approval of how 

gross energy output will be determined. 

(5) If you elect to comply with the 

part load NOX emissions standard, you 

must install, calibrate, maintain, and 

operate either a fuel flow meter (or flow 

meters) or an O2 or CO2 CEMS and a 

stack flow meter to continuously 

measure the heat input to the affected 

facility. 

(6) If you elect to comply with the 

temperature dependent NOX emissions 

standard, you must install, calibrate, 

maintain, and operate a thermometer to 

continuously monitor the ambient 

temperature. 

(7) If you burn natural gas with fuels 

other than natural gas and elect to 

comply with the fuels other than natural 

gas NOX emissions standard, you must 

install, calibrate, maintain, and operate 

a device to continuously monitor when 

a fuel other than natural gas fuel is 

combusted in the combustion turbine 

engine. 

(b) Each NOX CEMS must be installed 

and certified according to Performance 

Specification 2 (PS 2) in appendix B to 

this part. The span value must be 125 

percent of the highest applicable 

standard or highest anticipated hourly 

NOX emissions rate. For stationary 

combustion turbines that do not use 

post-combustion technology to reduce 

emissions of NOX to comply with the 

requirements of this subpart, the 

delegated permitting authority may 

approve the use of the NOX and diluent 

CEMS that are installed and certified 

according to appendix A of part 75 of 

this chapter in lieu of Procedure 1 in 

appendix F to this part and the 

requirements of § 60.13 of this part, 

except that the relative accuracy test 

audit (RATA) of the CEMS must be 

performed on a lb/MMBtu basis. 

(c) During each full operating hour, 

both the NOX monitor and the diluent 

monitor must complete a minimum of 

one cycle of operation (sampling, 

analyzing, and data recording) for each 

15-minute quadrant of the hour. For 

partial operating hours, at least one data 

point must be obtained with each 

monitor for each quadrant of the hour in 

which the unit operates. For operating 

hours in which required quality 

assurance and maintenance activities 

are performed on the CEMS, a minimum 

of two data points (one in each of two 

quadrants) are required for each 

monitor. 

(d) Each fuel flow meter must be 

installed, calibrated, maintained, and 

operated according to the 

manufacturer’s instructions. 

Alternatively fuel flow meters that meet 

the installation, certification, and 

quality assurance requirements in 

appendix D to part 75 of this chapter are 

acceptable for use under this subpart. 

(e) Each watt meter, steam flow meter, 

and each pressure or temperature 

measurement device must be installed, 

calibrated, maintained, and operated 

according to manufacturer’s 

instructions. 

(f) You must develop, submit to the 

delegated permitting authority for 

approval, maintain, and adhere to an 

on-site quality assurance (QA) plan for 

all of the continuous monitoring 

equipment you use to comply with this 

subpart. At a minimum, such a QA plan 

must address the requirements of 

§§ 60.13(d), (e), and (h) of this part. For 

the CEMS and fuel flow meters, the 

owner or operator of a stationary 

combustion turbine that does not use 

post combustion technology to reduce 

emissions of NOX to comply with the 

requirements of this subpart may, with 

approval of the delegated permitting 

authority, satisfy the requirements of 

this paragraph by implementing the QA 

program and plan described in section 

1 in appendix B to part 75 of this 

chapter in lieu of the requirements in 

§ 60.13(d)(1). 

§ 60.4350 How do I use the NOX CEMS 

data to determine excess emissions? 

(a) If you demonstrate continuous 

compliance using a CEMS for measuring 

NOX emissions, excess emissions are 

defined as the applicable compliance 

period for the stationary combustion 

turbine (either 4-operating hours or 30- 

operating days), during which the 

average NOX emissions from your 

affected facility measured by the CEMS 

is greater than the applicable maximum 

allowable NOX emissions standard 

specified in § 60.4320 as determined 

using the procedures specified in this 

section that apply to your stationary 

combustion turbine. 

(b) The NOX CEMS data for each 

operating hour as measured according to 

the requirements in § 60.4345 must be 

used to determine the hourly average 

NOX emissions. The hourly average for 

a given operating hour is the average of 

all data points for the operating hour. 

However, for any periods during which 

the NOX, diluent, flow, watt, steam 

pressure, or steam temperature monitors 

(as applicable) are out-of-control, the 

data points are not used in determining 

the hourly average NOX emissions. All 

data points that are not collected during 

out-of-control periods must be used to 

determine the hourly average NOX

emissions. 


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(c) For each operating hour in which 

an hourly average is obtained, the data 

acquisition and handling system must 

calculate and record the hourly average 

NOX emissions in units of ppm or lb/ 

MMBtu, using the appropriate equation 

from EPA Method 19 in appendix A–7 

of this part. For any hour in which the 

hourly average O2 concentration 

exceeds 19.0 percent O2 (or the hourly 

average CO2 concentration is less than 

1.0 percent CO2), a diluent cap value of 

19.0 percent O2 or 1.0 percent CO2 (as 

applicable) may be used in the emission 

calculations. 

(d) Correction of measured NOX

concentrations to 15 percent O2 is only 

allowed if you elect to comply with the 

ppm standard in Table 1 of this subpart. 

(e) Data used to meet the requirements 

of this subpart shall not include 

substitute data values derived from the 

missing data procedures of part 75 of 

this chapter, nor shall the data be bias 

adjusted according to the procedures of 

part 75 of this chapter. 

(f) All required fuel flow rate, steam 

flow rate, temperature, pressure, and 

megawatt data must be reduced to 

hourly averages. However, for any 

periods during which the flow, watt, 

steam pressure, or steam temperature 

monitors (as applicable) are out-ofcontrol, the data points are not used in 

determining the appropriate hourly 

average value 

(g) Calculate the hourly average NOX

emissions rate, in units of the emissions 

standard under § 60.4320, using either 

ppm or lb/MMBtu for units complying 

with the input-based standard or 

equation 1 of this subpart for units 

complying with the output-based 

standard: 

(1) For a stationary combustion 

turbine complying with an output-based 

emissions standard use Equation 1. 

Where: 

E = Hourly NOX emissions rate, in lb/MWh, 

(NOX)h = Average hourly NOX emissions rate, 

in lb/MMBtu, 

Q = Hourly heat input to the stationary 

combustion turbine, in MMBtu, 

measured using the fuel flowmeter(s), 

e.g., calculated using Equation D–15a in 

appendix D to part 75 of this chapter, an 

O2 or CO2 CEMS and a stack flow meter, 

or the methodologies in appendix F to 

part 75 of this chapter, and 

P = Gross energy output of the stationary 

combustion turbine in MWh. 

(2) The gross energy output is 

calculated as the sum of the total 

electrical and mechanical energy 

generated by the combustion turbine 

engine, the additional electrical or 

mechanical energy (if any) generated by 

the steam turbine following the heat 

recovery steam generating unit, and the 

total useful thermal energy output that 

is not used to generate additional 

electricity or mechanical output, 

expressed in equivalent MWh, as 

calculated using Equations 2 and 3 of 

this subpart: 

Where: 

P = Gross energy output of the stationary 

combustion turbine system in MWh, 

(Pe)t = Electrical or mechanical energy output 

of the stationary combustion turbine in 

MWh, 

(Pe)c = Electrical or mechanical energy 

output (if any) of the steam turbine in 

MWh, 

Ps = Useful thermal energy of the steam, 

measured relative to ISO conditions, not 

used to generate additional electric or 

mechanical output, in MWh, and 

Po = Other useful heat recovery, measured 

relative to ISO conditions, not used for 

steam generation or performance 

enhancement of the stationary 

combustion turbine. 

T = Electric Transmission and Distribution 

Factor. Equal to 0.95 for CHP combustion 

turbine where at least 20.0 percent of the 

total gross useful energy output consists 

of electric or direct mechanical output 

and 20.0 percent of the total gross useful 

energy output consists of useful thermal 

output on an annual basis. Equal to 1.0 

for all other combustion turbines. 

Where: 

Ps = Useful thermal energy of the steam, 

measured relative to ISO conditions, not 

used to generate additional electric or 

mechanical output, in MWh, 

Qm = Measured steam flow in lb, 

H = Enthalpy of the steam at measured 

temperature and pressure relative to ISO 

conditions, in Btu/lb, and 

3.413 × 106 = Conversion factor from Btu to 

MWh. 

(3) For mechanical drive applications 

complying with the output-based 

standard, use equation 4 of this subpart: 

Where: 

E = NOX emissions rate in lb/MWh, (NOX)m

= NOX emissions rate in lb/h, 

BL = Manufacturer’s base load rating of 

turbine, in MW, and 

AL = Actual load as a percentage of the base 

load rating. 

(h) For each simple cycle stationary 

combustion turbines, excess NOX

emissions are determined on a 4- 

operating hour averaging period basis 

using the NOX CEMS data and 

procedures specified in paragraphs 

(h)(1) through (4) of this section as 

applicable to the NOX emissions 

standard in Table 1 to this subpart. 

(1) For each 4-operating hour period, 

compute the 4-operating hour rolling 

average NOX emissions as the heat input 

weighted average of the hourly average 

of NOX emissions for a given operating 

hour and the 3 operating hours 

immediately preceding that operating 

hour using the applicable equation in 

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

section. If the 4-operating hour period 

contains more than one operating hour 

with no data points (one or more 

continuous monitors was out-of-control 

for the entire hour), report the 4- 

operating hour rolling average NOX

emissions rate determined for the period 

as occurring during a period with 

monitor downtime. 

(2) If you elect to comply with the 

applicable heat input-based emissions 

rate standard, calculate both the 4- 

operating hour rolling average NOX

emissions rate and the applicable 4- 

operating hour rolling average NOX

emissions standard, calculated using 

hourly values from in Table 1, using 

Equation 5 of this subpart. 


TKELLEY on DSK3SPTVN1PROD with PROPOSALSEP29AU12.000</GPH> EP29AU12.001</GPH> EP29AU12.002</GPH> EP29AU12.003</GPH>
Federal Register / Vol. 77, No. 168 / Wednesday, August 29, 2012 / Proposed Rules 52571 

Where: 

E = 4-operating hour rolling average NOX

emissions (lb/MMBtu or ng/J), 

Ei = Hourly average NOX emissions rate or 

emissions standard for operating hour 

‘‘i’’ (lb/MMBtu or ng/J), and 

Qi = Total heat input to stationary 

combustion turbine for operating hour 

‘‘i’’ (MMBtu or J as appropriate). 

(3) If you elect to comply with the 

applicable output-based emissions rate 

standard, calculate the 4-operating hour 

rolling average NOX emissions rate 

using equation 6–1 of this subpart. 

Calculate the applicable 4-operating 

hour rolling average NOX emissions 

standard, calculated using hourly values 

from in Table 1, using Equation 6–2 of 

this subpart. 

Where: 

E = 4-operating hour rolling average NOX

emissions rate (lb/MWh or ng/J), 

Ei = Hourly average NOX emissions rate for 

operating hour ‘‘i’’ (lb/MMBtu or ng/J), 

Qi = Total heat input to stationary 

combustion turbine for operating hour 

‘‘i’’ (MMBtu or J as appropriate), and 

Pi = Total gross energy output from stationary 

combustion turbine for operating hour 

‘‘i’’ (MWh or J). 

Where: 

E = 4-operating hour rolling average NOX

emissions standard (lb/MWh or ng/J), 

Ei = Hourly NOX emissions standard for 

operating hour ‘‘i’’ (lb/MWh or ng/J), and 

Pi = Total gross energy output from stationary 

combustion turbine for operating hour 

‘‘i’’ (MWh or J). 

(4) If you elect to comply with the 

applicable concentration standard using 

a numerical average, calculate both the 

4-operating hour rolling average NOX

emissions rate and the applicable 4- 

operating hour rolling average NOX

emissions standard, calculated using 

hourly values from in Table 1, using 

Equation 7 of this subpart. 

Where: 

E = 4-operating hour rolling average NOX

emissions (ppm), and 

Cavei = 1-hour average NOX concentration as 

determined using the procedure in 

§ 60.13(h) or emissions standard for 

operating hour ‘‘i’’ (ppm). 

(i) For each combined cycle 

combustion turbine and CHP 

combustion turbine, you must 

determine excess emissions on a 30 

operating-day rolling average basis. The 

measured emissions rate is the NOX

emissions measured by the CEMS for a 

given operating day and the 29 

operating days immediately preceding 

that day. Once each day, calculate a new 

30-operating day average measured 

emissions rate using all hourly average 

values based on non out-of-control NOX

emission data for all operating hours 

during the previous 30-operating day 

operating period. Report any 30- 

operating day periods for which you 

have less than 75 percent data 

availability as monitor downtime. If you 

elect to comply with the applicable heat 

input-based emissions rate standard, 

calculate both the measured emissions 

rate and emissions standard using 

Equation 8 of this subpart. If you elect 

to comply with the applicable outputbased emissions rate standard, calculate 

the measured emissions rate using 

Equation 9–1 of this subpart and 

calculate the emissions standard using 

Equation 9–2 of this subpart. If you elect 

to comply with the applicable 

concentration standard using a 

numerical average, calculate the 

measured emissions rate and emissions 

standard using Equation 10 of this 

subpart. 

Where: 

E = 30-operating day rolling average NOX

measured emissions rate or emissions 

standard for combined cycle combustion 

turbines and CHP combustion turbines 

(lb/MMBtu or ng/J), 

Ei = Hourly average NOX emissions rate or 

emissions standard for non out-ofcontrol operating hour ‘‘i’’ (lb/MMBtu or 

ng/J), 

Qi = Total heat input to stationary 

combustion turbine for non out-ofcontrol operating hour ‘‘i’’ (MMBtu or J 

as appropriate), and 

n = Total number of non out-of-control 

operating hours in the 30 operating-day 

period. 

Where: 

E = 30-operating day average NOX measured 

emissions rate for combined cycle 

combustion turbines and CHP 

combustion turbines (lb/MWh or ng/J), 

Ei = Hourly average NOX emissions rate for 

non out-of-control operating hour ‘‘i’’ 

(lb/MMBtu or ng/J), 

Qi = Total heat input to stationary 

combustion turbine for non out-ofcontrol operating hour ‘‘i’’ (MMBtu or J 

as appropriate), 

Pi = Total gross energy output from stationary 

combustion turbine for non out-ofcontrol operating hour ‘‘i’’ (MWh or J), 

and 

n = Total number of operating non out-ofcontrol hours in the 30 operating-day 

period. 

Where: 

E = 30-operating day average NOX emissions 

standard for combined cycle combustion 

turbines and CHP combustion turbines 

(lb/MWh or ng/J), 

Ei = Hourly NOX emissions standard for non 

out-of-control operating hour ‘‘i’’ (lb/ 

MWh or ng/J), 

Pi = Total gross energy output from stationary 

combustion turbine for non out-ofcontrol operating hour ‘‘i’’ (MWh or J), 

and 

n = Total number of operating non out-ofcontrol hours in the 30 operating-day 

period. 

Where: 

E = 30-operating day rolling average NOX

measured emissions rate or emissions 

standard for combined cycle combustion 

turbines and CHP combustion turbines 

(ppm), 

Cavei = 1-hour average NOX concentration as 

determined using the procedure in 

§ 60.13(h) or emissions standard for non 

out-of-control operating hour ‘‘i’’ (ppm), 

and 

n = Total number of operating hours in the 

30 operating-day period. 


TKELLEY on DSK3SPTVN1PROD with PROPOSALSEP29AU12.004</GPH> EP29AU12.005</GPH> EP29AU12.006</GPH> EP29AU12.007</GPH> EP29AU12.008</GPH> EP29AU12.009</GPH> EP29AU12.010</GPH> EP29AU12.011</GPH>
52572 Federal Register / Vol. 77, No. 168 / Wednesday, August 29, 2012 / Proposed Rules 

§ 60.4360 How do I use fuel sulfur analysis 

to determine the total sulfur content of the 

fuel combusted in my stationary 

combustion turbine? 

(a) If you elect to demonstrate 

compliance with a SO2 emissions 

standard according to § 60.4333(d)(2), 

the fuel analyses may be performed 

either by you, a service contractor 

retained by you, the fuel vendor, or any 

other qualified agency as determined by 

the delegated permitting authority using 

the sampling frequency specified in 

§ 60.4365. 

(b) Representative fuel analysis 

samples may be collected either 

manually or by an automatic sampling 

system. For automatic sampling, 

following ASTM D5287 (incorporated 

by reference, see § 60.17) for gaseous 

fuels or ASTM D4177 (incorporated by 

reference, see § 60.17) for liquid fuels. 

For reference purposes when manually 

collecting gaseous samples, see Gas 

Processors Association Standard 2166 

(incorporated by reference, see § 60.17). 

For reference purposes when manually 

collecting liquid samples, see either Gas 

Processors Association Standard 2174 or 

the procedures for manual pipeline 

sampling in section 14 of ASTM D4057 

(both of which are incorporated by 

reference, see § 60.17). 

(c) Each collected fuel analysis 

sample must be analyzed for the total 

sulfur content of the fuel and heating 

value using the methods specified in 

paragraphs (c)(1) or (2) of this section, 

as applicable to the fuel type. 

(1) For the sulfur content of liquid 

fuels, ASTM D129, or alternatively 

D1266, D1552, D2622, D4294, or D5453 

(all of which are incorporated by 

reference, see § 60.17). For the heating 

value of liquid fuels, ASTM D240 or 

D4809 (both of which are incorporated 

by reference, see § 60.17); or 

(2) For the sulfur content of gaseous 

fuels, ASTM D1072, or alternatively 

D3246, D4468, or D6667 (all of which 

are incorporated by reference, see 

§ 60.17). If the total sulfur content of the 

gaseous fuel during the most recent 

compliance demonstration was less than 

half the applicable standard, ASTM 

D4084, D4810, D5504, or D6228, or Gas 

Processors Association Standard 2377 

(all of which are incorporated by 

reference, see § 60.17), which measure 

the major sulfur compounds, may be 

used. For the heating value of gaseous 

fuels, ASTM D1826, or alternatively 

D3588, D4891, or D7164, or Gas 

Processors Association Standard 2172 

(all of which are incorporated by 

reference, see § 60.17). 

§ 60.4365 How frequently must I determine 

the fuel sulfur content? 

(a) If you are complying with 

requirements in § 60.4360, the total 

sulfur content of all fuels combusted in 

each stationary combustion turbine 

subject to an SO2 emissions standard in 

§ 60.4330 must be determined according 

to the schedule specified in paragraphs 

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

to the fuel type, unless you determine 

a custom schedule for the stationary 

combustion turbine according to 

paragraph (b) of this section. 

(1) Liquid fuel. Use one of the total 

sulfur sampling options and the 

associated sampling frequency 

described in sections 2.2.3, 2.2.4.1, 

2.2.4.2, and 2.2.4.3 in appendix D to 

part 75 of this chapter (i.e. flow 

proportional sampling, daily sampling, 

sampling from the unit’s storage tank 

after each addition of fuel to the tank, 

or sampling each delivery prior to 

combining it with liquid fuel already in 

the intended storage tank). 

(2) Gaseous fuel. If the fuel is 

supplied without intermediate bulk 

storage, the sulfur content value of the 

gaseous fuel must be determined and 

recorded once per operating day. 

(b) Custom schedules. As an 

alternative to the requirements of 

paragraph (a) of this section, you may 

implement custom schedules for 

determination of the total sulfur content 

of gaseous fuels, based on the design 

and operation of the affected facility and 

the characteristics of the fuel supply 

using the procedures provided in either 

paragraph (b)(1) and (2) of this section. 

Either you or the fuel vendor may 

perform the sampling. As an alternative 

to using one of these procedures, you 

may use a custom schedule that has 

been substantiated with data and 

approved by the Administrator or 

delegated authority as a change in 

monitoring prior to being used to 

comply with the applicable standard in 

§ 60.4330. 

(1) You may determine and 

implement a custom sulfur sampling 

schedule for your stationary combustion 

turbine using the procedure specified in 

paragraphs (b)(1)(i) through (iv) of this 

section. 

(i) Obtain daily total sulfur content 

measurements for 30 consecutive 

operating days, using the applicable 

methods specified in this subpart. Based 

on the results of the 30 daily samples, 

the required frequency for subsequent 

monitoring of the fuel’s total sulfur 

content must be as specified in 

paragraph (b)(1)(ii), (iii), or (iv) of this 

section, as applicable. 

(ii) If none of the 30 daily 

measurements of the fuel’s total sulfur 

content exceeds half the applicable 

standard, subsequent sulfur content 

monitoring may be performed at 12- 

month intervals provided the fuel 

source or supplier does not change. If 

any of the samples taken at 12-month 

intervals has a total sulfur content 

greater than half but less than the 

applicable standard, follow the 

procedures in paragraph (b)(1)(iii) of 

this section. If any measurement 

exceeds the applicable standard, follow 

the procedures in paragraph (b)(1)(iv) of 

this section. 

(iii) If at least one of the 30 daily 

measurements of the fuel’s total sulfur 

content is greater than half but less than 

the applicable standard, but none 

exceeds the applicable standard, then: 

(A) Collect and analyze a sample 

every 30 days for 3 months. If any sulfur 

content measurement exceeds the 

applicable standard, follow the 

procedures in paragraph (b)(1)(iv) of this 

section. Otherwise, follow the 

procedures in paragraph (b)(1)(iii)(B) of 

this section. 

(B) Begin monitoring at 6-month 

intervals for 12 months. If any sulfur 

content measurement exceeds the 

applicable standard, follow the 

procedures in paragraph (b)(1)(iv) of this 

section. Otherwise, follow the 

procedures in paragraph (b)(1)(iii)(C) of 

this section. 

(C) Begin monitoring at 12-month 

intervals. If any sulfur content 

measurement exceeds the applicable 

standard, follow the procedures in 

paragraph (b)(1)(iv) of this section. 

Otherwise, continue to monitor at this 

frequency. 

(iv) If a sulfur content measurement 

exceeds the applicable standard, 

immediately begin daily monitoring 

according to paragraph (c)(1)(i) of this 

section. Daily monitoring must continue 

until 30 consecutive daily samples, each 

having a sulfur content no greater than 

the applicable standard, are obtained. At 

that point, the applicable procedures of 

paragraph (b)(1)(ii) or (iii) of this section 

must be followed. 

(2) You may use the data collected 

from the 720-hour sulfur sampling 

demonstration described in section 2.3.6 

in appendix D to part 75 of this chapter 

to determine and implement a sulfur 

sampling schedule for your stationary 

combustion turbine using the procedure 

specified in paragraphs (b)(2)(i) through 

(iii) of this section. 

(i) If the maximum fuel sulfur content 

obtained from any of the 720 hourly 

samples does not exceed half the 

applicable standard, then the minimum 

required sampling frequency must be 

one sample at 12 month intervals. 


TKELLEY on DSK3SPTVN1PROD with PROPOSALS
Federal Register / Vol. 77, No. 168 / Wednesday, August 29, 2012 / Proposed Rules 52573 

(ii) If any sample result exceeds half 

the applicable standard, but none 

exceeds the applicable standard, follow 

the provisions of paragraph (b)(1)(iii) of 

this section. 

(iii) If the sulfur content of any of the 

720 hourly samples exceeds the 

applicable standard, follow the 

provisions of paragraph (b)(1)(iv) of this 

section. 

§ 60.4370 How do I demonstrate 

compliance with my SO2 emissions 

standard using records of the fuel sulfur 

content? 

(a) If you elect to demonstrate 

compliance with a SO2 emissions 

standard according to § 60.4333(d)(3), 

you must maintain on-site records (such 

as a current, valid purchase contract, 

tariff sheet, or transportation contract) 

documenting that total sulfur content 

for the fuel combusted in your 

stationary combustion turbine at all 

times does not exceed the conditions 

specified in paragraph (b) through (e) of 

this section, as applicable to your 

stationary combustion turbine. 

(b) If your stationary combustion 

turbine is subject to the SO2 emissions 

standard in § 60.4330(a), then the fuel 

combusted must have a potential SO2

emissions rate of 26 ng/J (0.060 lb/ 

MMBtu) heat input or less. 

(c) If your stationary combustion 

turbine is subject to the SO2 emissions 

standard in § 60.4330(b), then the total 

sulfur content of the gaseous fuel 

combusted must be 650 (mg/scm) (28 gr/ 

100 scf). 

(d) If your stationary combustion 

turbine is subject to the SO2 emissions 

standard in § 60.4330(c) or (d), the total 

sulfur content of the fuel combusted 

must be: 

(1) For natural gas, 140 gr/100 scf or 

less. 

(2) For fuel oil, 0.40 weight percent 

(4,000 ppmw) or less. 

(3) For other fuels, potential SO2

emissions of 180 ng/J (0.42 lb/MMBtu) 

heat input or less. 

(e) Representative fuel sampling data 

following the procedures specified in 

section 2.3.1.4 or 2.3.2.4 in appendix D 

to part 75 of this chapter documenting 

that the fuel meets the part 75 

requirements to be considered either 

pipeline natural gas or natural gas. 

§ 60.4372 How do I demonstrate 

compliance with my SO2 emissions 

standard and determine excess emissions 

using a SO2 CEMS? 

(a) If you demonstrate continuous 

compliance using a CEMS for measuring 

SO2 emissions, excess emissions are 

defined as the applicable averaging 

period, either 4-operating hour or 30- 

operating day, during which the average 

SO2 emissions from your stationary 

combustion turbine measured by the 

CEMS exceeds the applicable SO2

emissions standard specified in 

§ 60.4330 as determined using the 

procedures specified in this section that 

apply to your stationary combustion 

turbine. 

(b) You must install, calibrate, 

maintain, and operate a CEMS for 

measuring SO2 concentrations and 

either O2 or CO2 concentrations at the 

outlet of your stationary combustion 

turbine, and record the output of the 

system. 

(c) The 1-hour average SO2 emissions 

rate measured by a CEMS must be 

expressed in ng/J or lb/MMBtu heat 

input and must be used to calculate the 

average emissions rate under § 60.4330. 

(d) You must use the procedures for 

installation, evaluation, and operation 

of the CEMS as specified in § 60.13 and 

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

section. 

(1) Each CEMS must be operated 

according to the applicable procedures 

under Performance Specifications 1, 2, 

and 3 in appendix B of this part; 

(2) Quarterly accuracy determinations 

and daily calibration drift tests must be 

performed according to Procedure 1 in 

appendix F of this part; and 

(3) The span value of the SO2 CEMS 

at the outlet from the SO2 control device 

(or outlet of the stationary combustion 

turbine if no SO2 control device is used) 

must be 125 percent of either the 

highest applicable standard or highest 

potential SO2 emissions rate of the fuel 

combusted. 

(e) Correction of measured SO2

concentrations to 15 percent O2 is not 

allowed. 

(f) If you have installed and certified 

a SO2 CEMS that meets the 

requirements of part 75 of this chapter, 

the delegated permitting authority can 

approve that only quality assured data 

from the CEMS must be used to identify 

excess emissions under this subpart. 

You must report periods where the 

missing data substitution procedures in 

subpart D of part 75 are applied as 

monitoring system downtime in the 

excess emissions and monitoring 

performance report required under 

§ 60.7(c). 

(g) All required fuel flow rate, steam 

flow rate, temperature, pressure, and 

megawatt data must be reduced to 

hourly averages. 

(h) Calculate the hourly average SO2

emissions rate, in units of the emissions 

standard under § 60.4330, using lb/ 

MMBtu for units complying with the 

input-based standard or using equation 

11 of this subpart for units complying 

with the output-based standard: 

(1) For simple-cycle operation: 

Where: 

E = Hourly SO2 emissions rate, in lb/MWh, 

(SO2)h = Average hourly SO2 emissions rate, 

in lb/MMBtu, 

Q = Hourly heat input rate to the stationary 

combustion turbine, in MMBtu, 

measured using the fuel flow meter(s), 

e.g., calculated using Equation D–15a in 

appendix D to part 75 of this chapter, an 

O2 or CO2 CEMS and a stack flow meter, 

or the methodologies in appendix F to 

part 75 of this chapter, and 

P = Gross energy output of the stationary 

combustion turbine in MWh. 

(2) The gross energy output is 

calculated as the sum of the total 

electrical and mechanical energy 

generated by the stationary combustion 

turbine, the additional electrical or 

mechanical energy (if any) generated by 

the steam turbine following the heat 

recovery steam generating unit, and the 

total useful thermal energy output that 

is not used to generate additional 

electricity or mechanical output, 

expressed in equivalent MWh, as 

calculated using Equations 12 and 13 of 

this subpart. 

Where: 

P = Gross energy output of the stationary 

combustion turbine system in MWh, 

(Pe)t = Electrical or mechanical energy output 

of the stationary combustion turbine in 

MWh, 

(Pe)c = Electrical or mechanical energy 

output (if any) of the steam turbine in 

MWh, 


TKELLEY on DSK3SPTVN1PROD with PROPOSALSEP29AU12.012</GPH> EP29AU12.013</GPH>
52574 Federal Register / Vol. 77, No. 168 / Wednesday, August 29, 2012 / Proposed Rules 

Ps = Useful thermal energy of the steam, 

measured relative to ISO conditions, not 

used to generate additional electric or 

mechanical output, in MWh, and 

Po = Other useful heat recovery, measured 

relative to ISO conditions, not used for 

steam generation or performance 

enhancement of the stationary 

combustion turbine. 

T = Electric Transmission and Distribution 

Factor. Equal to 0.95 for CHP combustion 

turbine where at least 20.0 percent of the 

total gross useful energy output consists 

of electric or direct mechanical output 

and 20.0 percent of the total gross useful 

energy output consists of useful thermal 

output on an annual basis. Equal to 1.0 

for all other combustion turbines. 

Where: 

Ps = Useful thermal energy of the steam, 

measured relative to ISO conditions, not 

used to generate additional electric or 

mechanical output, in MWh, 

Qm = Measured steam flow rate in lb, 

H = Enthalpy of the steam at measured 

temperature and pressure relative to ISO 

conditions, in Btu/lb, and 

3.413 × 106 = Conversion factor from Btu to 

MWh. 

(3) For mechanical drive applications 

complying with the output-based 

standard, use equation 14 of this 

subpart: 

Where: 

E = SO2 emissions rate in lb/MWh, 

(SO2)m = SO2 emissions rate in lb/h, 

BL = Manufacturer’s base load rating of 

turbine, in MW, and 

AL = Actual load as a percentage of the base 

load rating. 

(i) For stationary combustion turbines 

other than combined cycle combustion 

turbines and CHP combustion turbines, 

you must determine excess emissions 

on a 4-operating hour rolling average 

basis. The ‘‘4-operating hour rolling 

average SO2 measured emissions rate’’ is 

the SO2 emissions measured by the 

CEMS for a given operating hour and 

the 3 consecutive operating hours 

immediately preceding that hour 

expressed in the units appropriate for 

the SO2 emissions standard that is 

applied to your stationary combustion 

turbine. Each operating hour, calculate 

the 4-operating hour rolling average SO2

measured emissions rate using all of the 

non out-of-control SO2 emission data 

obtained during the previous 4- 

operating hour operating period. If the 

4-operating hour period contains more 

than one operating hour with no data 

points (one or more CEMS was out-ofcontrol for the entire hour), report the 4- 

operating hour rolling average SO2

emissions rate determined for the period 

as occurring during a period with 

monitor downtime. If you elect to 

comply with the applicable heat inputbased emissions rate standard, calculate 

both the measured emissions rate and 

the emissions standard using Equation 

15 of this subpart. If you elect to comply 

with the applicable output-based 

emissions standard, calculate the 

measured emissions rate using Equation 

16–1 of this subpart and calculate the 

emissions standard using Equation 16– 

2 of this subpart. 

Where: 

E = 4-operating hour rolling average SO2

measured emissions rate or emissions 

standard for stationary combustion 

turbines other than combined cycle 

combustion turbines and CHP 

combustion turbines (lb/MMBtu or ng/J), 

Ei = Hourly average SO2 emissions rate or 

emissions standard for non out-of-control 

operating hour ‘‘i’’ (lb/MMBtu or ng/J), and 

Qi = Total heat input to stationary 

combustion turbine for non out-of-control 

operating hour ‘‘i’’ (MMBtu or J as 

appropriate). 

Where: 

E = 4-operating hour rolling average SO2

measured emissions rate for stationary 

combustion turbines other than 

combined cycle combustion turbines and 

CHP combustion turbines (lb/MWh or 

ng/J), 

Ei = Hourly average SO2 emissions rate for 

non out-of-control operating hour ‘‘i’’ 

(lb/MMBtu or ng/J), 

Qi = Total heat input to stationary 

combustion turbine for non out-ofcontrol operating hour ‘‘i’’ (MMBtu or J 

as appropriate), and 

Pi = Total gross energy output from stationary 

combustion turbine for non out-ofcontrol operating hour ‘‘i’’ (MWh or J). 

Where: 

E = 4-operating hour rolling average SO2

emissions standard for stationary 

combustion turbines other than 

combined cycle combustion turbines and 

CHP combustion turbines (lb/MWh or 

ng/J), 

Ei = Hourly SO2 emissions standard for non 

out-of-control operating hour ‘‘i’’ (lb/ 

MMBtu or ng/J), and 

Pi = Total gross energy output from stationary 

combustion turbine for non out-ofcontrol operating hour ‘‘i’’ (MWh or J). 

(ii) For combined cycle combustion 

turbines and CHP combustion turbines, 

you must determine excess emissions 

on a 30 operating-day rolling average 

basis. The excess emissions level is the 

heat input weighted-average of the SO2

emissions measured by the CEMS for a 

given operating day and the 29 

operating days immediately preceding 

that day. Once each day, calculate a new 

30-operating day average measured 

emissions rate using all hourly average 

values based on non out-of-control SO2

emission data for all operating hours 

during the previous 30-operating day 

operating period. Report any 30- 

operating day periods for which you 

have less than 75 percent data 

availability as monitor downtime. If you 

elect to comply with the applicable heat 

input-based emissions standard, 

calculate the measured emissions rate 

and emissions rate using Equation 17 of 

this subpart. If you elect to comply with 

the applicable output-based standard, 

calculate the measured emissions rate 

using Equation 18–1 of this subpart and 

calculate the emissions standard using 

Equation 18–2 of this subpart. 

Where: 


TKELLEY on DSK3SPTVN1PROD with PROPOSALSEP29AU12.014</GPH> EP29AU12.015</GPH> EP29AU12.016</GPH> EP29AU12.017</GPH> EP29AU12.018</GPH> EP29AU12.019</GPH>
Federal Register / Vol. 77, No. 168 / Wednesday, August 29, 2012 / Proposed Rules 52575 

E = 30-operating day rolling average SO2

measured emissions rate or emissions 

standard for combined cycle combustion 

turbines and CHP combustion turbines 

(lb/MMBtu or ng/J), 

Ei = Hourly average SO2 emissions rate or 

emissions standard for non out-ofcontrol operating hour ‘‘i’’ (lb/MMBtu or 

ng/J), 

Qi = Total heat input to stationary 

combustion turbine for non out-ofcontrol operating hour ‘‘i’’ (MMBtu or J 

as appropriate), and 

n = Total number of non out-of-control 

operating hours in the 30 operating-day 

period. 

Where: 

E = 30-operating day average SO2 measured 

emissions rate for combined cycle 

combustion turbines and CHP 

combustion turbines (lb/MWh or ng/J), 

Ei = Hourly average SO2 measured emissions 

rate for non out-of-control operating hour 

‘‘i’’ (lb/MMBtu or ng/J), 

Qi = Total heat input to stationary 

combustion turbine for non out-ofcontrol operating hour ‘‘i’’ (MMBtu or J 

as appropriate), 

Pi = Total gross energy output from stationary 

combustion turbine for non out-ofcontrol operating hour ‘‘i’’ (MWh or J), 

and 

n = Total number of non out-of-control 

operating hours in the 30 operating-day 

period. 

Where: 

E = 30-operating day average SO2 emissions 

standard for combined cycle combustion 

turbines and CHP combustion turbines 

(lb/MWh or ng/J), 

Ei = Hourly SO2 emissions standard for non 

out-of-control operating hour ‘‘i’’ (lb/ 

MWh or ng/J), 

Pi = Total gross energy output from stationary 

combustion turbine for non out-ofcontrol operating hour ‘‘i’’ (MWh or J), 

and 

n = Total number of non out-of-control 

operating hours in the 30 operating-day 

period. 

Recordkeeping and Reporting 

§ 60.4375 What reports must I submit? 

(a) An owner or operator of a 

stationary combustion turbine that 

elects to continuously monitor 

parameters or emissions, or to 

periodically determine the fuel sulfur 

content under this subpart, must submit 

reports of excess emissions and monitor 

downtime, according to § 60.7(c). Excess 

emissions must be reported for all 

periods of unit operation, including 

startup, shutdown, and malfunction. 

(b) An owner or operator of a 

stationary combustion turbine that 

performs performance tests to 

demonstrate compliance with this 

subpart must submit a written report of 

the results of each performance test 

before the close of business on the 60th 

day following the completion of the 

performance test, except as specified in 

paragraph (c) of this part. 

(c)(1) Within 60 days after the date of 

completing each performance test (see 

§ 60.8) as required by this subpart you 

must submit the results of the 

performance tests required by this 

subpart to EPA’s WebFIRE database by 

using the Compliance and Emissions 

Data Reporting Interface (CEDRI) that is 

accessed through EPA’s Central Data 

Exchange (CDX) (www.epa.gov/cdx). 

Performance test data must be submitted 

in the file format generated through use 

of EPA’s Electronic Reporting Tool 

(ERT) (see http://www.epa.gov/ttn/chief/ 

ert/index.html). Only data collected 

using test methods on the ERT Web site 

are subject to this requirement for 

submitting reports electronically to 

WebFIRE. Owners or operators who 

claim that some of the information being 

submitted for performance tests is 

confidential business information (CBI) 

must submit a complete ERT file 

including information claimed to be CBI 

on a compact disk or other commonly 

used electronic storage media 

(including, but not limited to, flash 

drives) to EPA. The electronic media 

must be clearly marked as CBI and 

mailed to U.S. EPA/OAPQS/CORE CBI 

Office, Attention: WebFIRE 

Administrator, MD C404–02, 4930 Old 

Page Rd., Durham, NC 27703. The same 

ERT file with the CBI omitted must be 

submitted to EPA via CDX as described 

earlier in this paragraph. At the 

discretion of the delegated authority, 

you must also submit these reports, 

including the confidential business 

information, to the delegated authority 

in the format specified by the delegated 

authority. 

(2) Within 60 days after the date of 

completing each CEMS performance 

evaluation test (see § 60.13), you must 

submit the relative accuracy test audit 

data electronically into EPA’s Central 

Data Exchange by using the Electronic 

Reporting Tool as mentioned in 

paragraph (c)(1) of this section. Only 

data collected using test methods 

compatible with ERT are subject to this 

requirement to be submitted 

electronically to EPA’s CDX. 

(3) All reports required by this 

subpart not subject to the requirements 

in paragraphs (c)(1) and (2) of this 

section must be sent to the 

Administrator or delegated authority at 

the appropriate address listed in § 63.13. 

The Administrator or delegated 

authority may request a report in any 

form suitable for the specific case (e.g., 

by commonly used electronic media 

such as Excel spreadsheet, on CD or 

hard copy). The Administrator or 

delegated authority retains the right to 

require submittal of reports subject to 

paragraphs (c)(1) and (2) of this section 

in paper format. 

(d) The notification requirements of 

§ 60.8 apply to the initial and 

subsequent performance tests. 

(e) An owner or operator of an 

affected facility complying with 

§ 60.4333(b)(3) must notify the 

delegated permitting authority within 

15 calendar days after the facility 

recommences operation. 

(f) An owner or operator of an affected 

facility complying with § 60.4333(b)(4) 

must notify the delegated permitting 

authority within 15 calendar days after 

the facility has operated more than 50 

operating hours since the date the 

previous performance test was required 

to be conducted. 

§ 60.4380 How are NOX excess emissions 

and monitor downtime reported? 

(a) For reports required under 

§ 60.4375(a), periods of excess 

emissions and monitor downtime for 

stationary combustion turbines using 

water or steam to fuel ratio monitoring 

are reported as specified in paragraphs 

(a)(1) through (3) of this section. 

(1) An excess emission that must be 

reported is any operating hour for which 

the 4-operating hour rolling average 

steam or water to fuel ratio, as measured 

by the continuous monitoring system, is 

less than the acceptable steam or water 

to fuel ratio needed to demonstrate 

compliance with § 60.4320, as 

established during the most recent 

performance test. Any operating hour 

during which no water or steam is 

injected into the turbine when the 

specific conditions require water or 

steam injection for NOX control will 

also be considered an excess emission. 

(2) A period of monitor downtime that 

must be reported is any operating hour 

in which water or steam is injected into 

the turbine, but the parametric data 

needed to determine the steam or water 

to fuel ratio are unavailable or out-ofcontrol. 

(3) Each report must include the 

average steam or water to fuel ratio, 


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average fuel consumption, and the 

stationary combustion turbine load 

during each excess emission. 

(b) For reports required under 

§ 60.4375(a), periods of excess 

emissions and monitor downtime for 

stationary combustion turbines using a 

CEMS, excess emissions are reported as 

specified in paragraphs (b)(1) through 

(3) of this section. 

(1) An excess emission that must be 

reported is any unit operating period in 

which the 4-operating hour or 30- 

operating day rolling average NOX

emissions rate exceeds the applicable 

emissions standard in § 60.4320 as 

determined in § 60.4350. 

(2) A period of monitor downtime that 

must be reported is any operating hour 

in which the data for any of the 

following parameters are either missing 

or out-of-control: NOX concentration, 

CO2 or O2 concentration, stack flow rate, 

heat input rate, steam flow rate, steam 

temperature, steam pressure, or 

megawatts. You are only required to 

monitor parameters used for compliance 

purposes. 

(3) For hours with multiple emission 

standards, the applicable standard for 

that hour is determined based on the 

condition, excluding periods of monitor 

downtime, that corresponded to the 

highest emissions standard. 

(c) For reports required under 

§ 60.4375(a), periods of excess 

emissions and monitor downtime for 

stationary combustion turbines using 

combustion parameters or parameters 

that document proper operation of the 

NOX emission controls excess emissions 

and monitor downtime are reported as 

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

this section. 

(1) Excess emissions that must be 

reported are each 4-operating hour 

rolling average in which any monitored 

parameter (as averaged over the 4 

operating-hour period) does not achieve 

the target value or is outside the 

acceptable range defined in the 

parameter monitoring plan for the unit. 

(2) Periods of monitor downtime that 

must be reported are each operating 

hour in which any of the required 

parametric data are either not recorded 

or are out-of-control. 

§ 60.4385 How are SO2 excess emissions 

and monitor downtime reported? 

(a) If you choose the option to monitor 

the sulfur content of the fuel, excess 

emissions and monitor downtime are 

defined as follows: 

(1) For samples obtained using daily 

sampling, flow proportional sampling, 

or sampling from the unit’s storage tank, 

excess emissions occur each operating 

hour included in the period beginning 

on the date and hour of any sample for 

which the sulfur content of the fuel 

being fired in the stationary combustion 

turbine exceeds the applicable standard 

and ending on the date and hour that a 

subsequent sample is taken that 

demonstrates compliance with the 

sulfur standard. 

(2) If the option to sample each 

delivery of fuel oil has been selected, 

you must immediately switch to one of 

the other oil sampling options (i.e., 

daily sampling, flow proportional 

sampling, or sampling from the unit’s 

storage tank) if the sulfur content of a 

delivery exceeds 0.05 weight percent, 

0.15 weight percent, or 0.40 weight 

percent as applicable. You must 

continue to use one of the other 

sampling options until all of the oil 

from the delivery has been combusted, 

and you must evaluate excess emissions 

according to paragraph (a) of this 

section. When all of the fuel from the 

delivery has been combusted, you may 

resume using the as-delivered sampling 

option. 

(3) A period of monitor downtime 

begins when a required sample is not 

taken by its due date. A period of 

monitor downtime also begins on the 

date and hour of a required sample, if 

invalid results are obtained. The period 

of monitor downtime ends on the date 

and hour of the next valid sample. 

(b) If you choose the option to 

maintain records of the fuel sulfur 

content, excess emissions are defined as 

any period during which you burn a 

fuel that you do not have appropriate 

fuel records or that fuel contains sulfur 

greater than the applicable standard. 

(c) For reports required under 

§ 60.4375(a), periods of excess 

emissions and monitor downtime for 

stationary combustion turbines using a 

CEMS, excess emissions are reported as 

specified in paragraphs (c)(1) through 

(2) of this section. 

(1) An excess emission that must be 

reported is any unit operating period in 

which the 4-operating hour or 30- 

operating day rolling average SO2

emissions rate exceeds the applicable 

emissions standard in § 60.4330 as 

determined in § 60.4372. 

(2) A period of monitor downtime that 

must be reported is any operating hour 

in which the data for any of the 

following parameters are either missing 

or out-of-control: SO2 concentration, 

CO2 or O2 concentration, stack flow rate, 

heat input rate, steam flow rate, steam 

temperature, steam pressure, or 

megawatts. You are only required to 

monitor parameters used for compliance 

purposes. 

§ 60.4390 What records must I maintain? 

(a) You must maintain records of your 

information used to demonstrate 

compliance with this subpart as 

specified in § 60.7. 

(b) An owner or operator of a 

stationary combustion turbine that uses 

the other fuels, part-load, or low 

temperature NOX standards in the 

compliance demonstration must 

maintain concurrent records of the 

hourly heat input, percent load, ambient 

temperature, and emissions data as 

applicable. 

(c) An owner or operator of a 

stationary combustion turbine that uses 

the tuning NOX standard in the 

compliance demonstration must 

identify the hours on which the 

maintenance was performed and a 

description of the maintenance. 

(d) An owner or operator of a 

stationary combustion turbine that 

demonstrates compliance using the 

output-based standard must maintain 

concurrent records of the total gross 

energy output and emissions data. 

(e) An owner or operator of a 

stationary combustion turbine that 

demonstrates compliance using the 

water or steam to fuel ratio or a 

parameter continuous monitoring 

system must maintain continuous 

records of the appropriate parameters. 

(f) An owner or operator of a 

stationary combustion turbine 

complying with the fuel based SO2

standard must maintain records of the 

results of all fuel analyses or a current, 

valid purchase contract, tariff sheet, or 

transportation contract. 

§ 60.4395 When must I submit my reports? 

Consistent with § 60.7(c), all reports 

required under § 60.7(c) must be 

postmarked by the 30th day following 

the end of each 6-month period. 

Performance Tests 

§ 60.4400 How do I conduct performance 

tests to demonstrate compliance with my 

NOX emissions standard if I do not have a 

NOX CEMS? 

(a) You must conduct the performance 

test according to the requirements in 

§ 60.8 and paragraphs (b) through (d) of 

this section. 

(b) You must use the methods in 

either paragraph (b)(1) or (2) of this 

section to measure the NOX

concentration for each test run. 

(1) Measure the NOX concentration 

using EPA Method 7E in appendix A– 

4 of this part or EPA Method 20 in 

appendix A–7 of this part. In addition, 

when only natural gas is being 

combusted ASTM D6522 (incorporated 

by reference, see § 60.17) can be used 

instead of EPA Method 20 in appendix 


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A–7 of this part to determine the oxygen 

content in the exhaust gas. For units 

complying with the output-based 

standard, concurrently measure the 

stack gas flow rate, using EPA Methods 

1 and 2 in appendix A–1 of this part, 

and measure and record the electrical 

and thermal output from the unit. Then, 

use Equation 19 of this subpart to 

calculate the NOX emissions rate: 

Where: 

E = NOX emissions rate, in lb/MWh, 

1.194 × 10¥7 = Conversion constant, in lb/ 

dscf-ppm, 

(NOX)c = Average NOX concentration for the 

run, in ppm, 

Qstd = Average stack gas volumetric flow rate, 

in dscf/h, and 

P = Average gross electrical and mechanical 

energy output of the stationary 

combustion turbine, in MW (for simplecycle operation), for combined-cycle 

operation, the sum of all electrical and 

mechanical output from the combustion 

and steam turbines, or, for CHP 

operation, the sum of all electrical and 

mechanical output from the combustion 

and steam turbines plus all useful 

recovered thermal output not used for 

additional electric or mechanical 

generation or to enhance the 

performance of the stationary 

combustion turbine, in MW, calculated 

according to § 60.4350. 

(2) Measure the NOX and diluent gas 

concentrations, using either EPA 

Method 7E in appendix A–4 of this part 

and EPA Method 3A in appendix A–2 

of this part, or EPA Method 20 in 

appendix A–7 of this part. In addition, 

when only natural gas is being 

combusted ASTM D6522 (incorporated 

by reference, see § 60.17) can be used 

instead of EPA Method 3A in appendix 

A–2 of this part or EPA Method 20 in 

appendix A–7 of this part to determine 

the oxygen content in the exhaust gas. 

Concurrently measure the heat input to 

the unit, using a fuel flowmeter (or 

flowmeters), an O2 or CO2 CEMS along 

with a stack flow meter, or the 

methodologies in appendix F to part 75 

of this chapter, and for units complying 

with the output-based standard measure 

the electrical, mechanical, and thermal 

output of the unit. Use EPA Method 19 

in appendix A–7 of this part to calculate 

the NOX emissions rate in lb/MMBtu. 

Then, use Equations 1 and, if necessary, 

2 and 3 of this subpart in § 60.4350(f) to 

calculate the NOX emissions rate in lb/ 

MWh. 

(c) You must use the methods in 

either paragraph (c)(1) or (2) of this 

section to select the sampling traverse 

points for NOX and (if applicable) 

diluent gas. 

(1) You must select the sampling 

traverse points for NOX and (if 

applicable) diluent gas according to EPA 

Method 20 in appendix A–7 of this part 

or EPA Method 1 in appendix A–1 of 

this part (non-particulate procedures), 

and sampled for equal time intervals. 

The sampling must be performed with 

a traversing single-hole probe, or, if 

feasible, with a stationary multi-hole 

probe that samples each of the points 

sequentially. Alternatively, a multi-hole 

probe designed and documented to 

sample equal volumes from each hole 

may be used to sample simultaneously 

at the required points. 

(2) As an alternative to paragraph 

(c)(1) of this section, you may select the 

sampling traverse points for NOX and (if 

applicable) diluent gas according to 

requirements in paragraphs (c)(2)(i) and 

(ii) of this section. 

(i) You perform a stratification test for 

NOX and diluent pursuant to the 

procedures specified in section 

6.5.6.1(a) through (e) in appendix A of 

part 75 of this chapter. 

(ii) Once the stratification sampling is 

completed, you use the following 

alternative sample point selection 

criteria for the performance test 

specified in paragraphs (c)(2)(ii)(A) 

through ( 

(A) If each of the individual traverse 

point NOX concentrations is within ±10 

percent of the mean concentration for 

all traverse points, or the individual 

traverse point diluent concentrations 

differs by no more than ±0.5 percent 

CO2 (or O2) from the mean for all 

traverse points, then you may use three 

points (located either 16.7, 50.0 and 

83.3 percent of the way across the stack 

or duct, or, for circular stacks or ducts 

greater than 2.4 meters (7.8 feet) in 

diameter, at 0.4, 1.2, and 2.0 meters 

from the wall). The three points must be 

located along the measurement line that 

exhibited the highest average NOX

concentration during the stratification 

test; or 

(B) For a stationary combustion 

turbine subject to a NOX emissions 

standard greater than 15 ppm at 15 

percent O2, you may sample at a single 

point, located at least 1 meter from the 

stack wall or at the stack centroid if 

each of the individual traverse point 

NOX concentrations is within ±5 percent 

of the mean concentration for all 

traverse points, or the individual 

traverse point diluent concentrations 

differs by no more than ±0.3 percent 

CO2 (or O2) from the mean for all 

traverse points; or 

(C) For a stationary combustion 

turbine subject to a NOX emissions 

standard less than or equal to 15 ppm 

at 15 percent O2, you may sample at a 

single point, located at least 1 meter 

from the stack wall or at the stack 

centroid if each of the individual 

traverse point NOX concentrations is 

within ±2.5 percent of the mean 

concentration for all traverse points, or 

the individual traverse point diluent 

concentrations differs by no more than 

±0.15 percent CO2 (or O2) from the mean 

for all traverse points. 

(d) The performance test must be 

done at any load condition within plus 

or minus 25 percent of 100 percent of 

the base load rating. You may perform 

testing at the highest achievable load 

point, if at least 75 percent of the base 

load rating cannot be achieved in 

practice. You must conduct three 

separate test runs for each performance 

test. The minimum time per run is 60 

minutes. 

(1) If the stationary combustion 

turbine combusts both natural gas and 

fuels other than natural gas as primary 

or backup fuels, separate performance 

testing is required for each fuel. 

(2) For a combined cycle or CHP 

combustion turbine with supplemental 

heat (duct burner), you must measure 

the total NOX emissions downstream of 

the duct burner. The duct burner must 

be in operation during the performance 

test. 

(3) If water or steam injection is used 

to control NOX with no additional postcombustion NOX control and you 

choose to monitor the steam or water to 

fuel ratio in accordance with § 60.4335, 

then that monitoring system must be 

operated concurrently with each EPA 

Method 20 in appendix A–7 of this part 

or EPA Method 7E in appendix A–4 of 

this part run and must be used to 

determine the fuel consumption and the 

steam or water to fuel ratio necessary to 

comply with the applicable § 60.4320 

NOX emissions standard. 

(4) If you elect to install a CEMS, the 

performance evaluation of the CEMS 

may either be conducted separately or 


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(as described in § 60.4405) as part of the 

initial performance test of the affected 

unit. 

(5) The ambient temperature must be 

greater than 0 °F during the performance 

test. The delegated permitting authority 

may approve performance testing below 

0 °F if the timing of the required 

performance test and environmental 

conditions make it impractical to test at 

ambient conditions greater than 0 °F. 

§ 60.4405 How do I conduct a performance 

test if I use a NOX CEMS? 

(a) If you use a CEMS the performance 

test must be performed according to the 

procedures specified in paragraph (b) of 

this section. 

(b) The initial performance test must 

use the procedure specified in 

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

section. 

(1) Perform a minimum of nine RATA 

reference method runs, with a minimum 

time per run of 21 minutes, at a single 

load level, within plus or minus 25 

percent of 100 percent of the base load 

rating. You may perform testing at the 

highest achievable load point, if at least 

75 percent of the base load rating cannot 

be achieved in practice. The ambient 

temperature must be greater than 0 °F 

during the RATA runs. The delegated 

permitting authority may approve 

performance testing below 0 °F if the 

timing of the required performance test 

and environmental conditions make it 

impractical to test at ambient conditions 

greater than 0 °F. 

(2) For each RATA run, concurrently 

measure the heat input to the unit using 

a fuel flow meter (or flow meters) or the 

methodologies in appendix F to part 75 

of this chapter, and for units complying 

with the output-based standard, 

measure the electrical and thermal 

output from the unit. 

(3) Use the test data both to 

demonstrate compliance with the 

applicable NOX emissions standard 

under § 60.4320 and to provide the 

required reference method data for the 

RATA of the CEMS described under 

§ 60.4342. 

(4) Compliance with the applicable 

emissions standard in § 60.4320 is 

achieved if the sum of the NOX

emissions divided by the heat input (or 

gross energy output) for all the RATA 

runs, expressed in units of lb/MMBtu or 

lb/MWh, does not exceed the emissions 

standard. 

§ 60.4415 How do I conduct performance 

tests to demonstrate compliance with my 

SO2 emissions standard? 

(a) An owner or operator of an 

affected facility complying with the fuel 

based standard must submit fuel records 

(such as a current, valid purchase 

contract, tariff sheet, transportation 

contract, or results of a fuel analysis) to 

satisfy the requirements of § 60.8. 

(b) An owner or operator of an 

affected facility complying with the SO2

emissions standard must conduct the 

performance test by measuring the SO2

emissions in the stationary combustion 

turbine exhaust gases using the methods 

in either paragraph (b)(1) or (2) of this 

section. 

(1) Measure the SO2 concentration 

using EPA Methods 6, 6C, 8 in appendix 

A–4 of this part, or EPA Method 20 in 

appendix A–7 of this part. In addition, 

the American Society of Mechanical 

Engineers (ASME) standard, ASME PTC 

19–10–1981–Part 10, ‘‘Flue and Exhaust 

Gas Analyses,’’ manual methods for 

sulfur dioxide (incorporated by 

reference, see § 60.17) can be used 

instead of EPA Method 6 in appendix 

A–4 of this part or EPA Method 20 in 

appendix A–7 of this part. For units 

complying with the output based 

standard, concurrently measure the 

stack gas flow rate, using EPA Methods 

1 and 2 in appendix A–1 of this part, 

and measure and record the electrical 

and thermal output from the unit. Then 

use Equation 20 of this subpart to 

calculate the SO2 emissions rate: 

Where: 

E = SO2 emissions rate, in lb/MWh, 

1.664 × 10¥7 = Conversion constant, in lb/ 

dscf-ppm, 

(SO2)c = Average SO2 concentration for the 

run, in ppm, 

Qstd = Average stack gas volumetric flow rate, 

in dscf/h, and 

P = Average gross electrical and mechanical 

energy output of the stationary 

combustion turbine, in MW (for simplecycle operation), for combined-cycle 

operation, the sum of all electrical and 

mechanical output from the combustion 

and steam turbines, or, for CHP 

operation, the sum of all electrical and 

mechanical output from the combustion 

and steam turbines plus all useful 

recovered thermal output not used for 

additional electric or mechanical 

generation or to enhance the 

performance of the stationary 

combustion turbine, in MW, calculated 

according to § 60.4350(f)(2). 

(2) Measure the SO2 and diluent gas 

concentrations, using either EPA 

Methods 6, 6C, or 8 in appendix A–4 of 

this part and EPA Method 3A in 

appendix A–2 of this part, or EPA 

Method 20 in appendix A–7 of this part. 

In addition, you may use the manual 

methods for sulfur dioxide ASME PTC 

19–10–1981–Part 10 (incorporated by 

reference, see § 60.17). Concurrently 

measure the heat input to the unit, using 

a fuel flowmeter (or flowmeters), an O2

or CO2 CEMS along with a stack flow 

meter, or the methodologies in appendix 

F to part 75 of this chapter, and for units 

complying with the output based 

standard measure the electrical and 

thermal output of the unit. Use EPA 

Method 19 in appendix A–7 of this part 

to calculate the SO2 emissions rate in 

lb/MMBtu. Then, use Equations 11 and, 

if necessary, 12 and 13 of this subpart 

in § 60.4372 to calculate the SO2

emissions rate in lb/MWh. 

Definitions 

§ 60.4420 What definitions apply to this 

subpart? 

As used in this subpart, all terms not 

defined herein will have the meaning 

given them in the Clean Air Act and in 

subpart A (General Provisions) of this 

part. 

Affirmative defense means, in the 

context of an enforcement proceeding, a 

response or defense put forward by a 

defendant, regarding which the 

defendant has the burden of proof, and 

the merits of which are independently 

and objectively evaluated in a judicial 

or administrative proceeding. 

Base load rating means 100 percent of 

the manufacturer’s design heat input 

capacity of the combustion turbine 

engine at ISO conditions using the 

higher heating value of the fuel. 

Biogas means gas produced by the 

anaerobic digestion or fermentation of 

organic matter including manure, 

sewage sludge, municipal solid waste, 

biodegradable waste, or any other 

biodegradable feedstock, under 

anaerobic conditions. Biogas is 

comprised primarily of methane and 

CO2.

Byproduct means any liquid or 

gaseous substance produced at chemical 

manufacturing plants, petroleum 

refineries, or pulp and paper mills 

(except natural gas and fuel oil) and 

combusted in a stationary combustion 


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turbine. Gaseous substances with CO2

levels greater than 50 percent or carbon 

monoxide levels greater than 10 percent 

are not byproduct. 

Combined cycle combustion turbine 

means any stationary combustion 

turbine which recovers heat from the 

combustion turbine engine exhaust 

gases to generate steam that is used 

exclusively to create additional power 

output in a steam turbine. 

Combined heat and power (CHP) 

combustion turbine means any 

stationary combustion turbine which 

recovers heat from the combustion 

turbine engine exhaust gases to heat 

water or another medium, generate 

steam for useful purposes other than 

exclusively for additional electric 

generation, or directly uses the heat in 

the exhaust gases for a useful purpose. 

Combustion turbine engine means the 

air compressor, combustor, and turbine 

sections of a stationary combustion 

turbine. 

Combustion turbine test cell/stand 

means any apparatus used for testing 

uninstalled stationary or uninstalled 

mobile (motive) combustion turbines. 

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), 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), kerosine, as 

defined by the American Society of 

Testing and Materials in ASTM D3699 

(incorporated by reference, see § 60.17), 

biodiesel as defined by the American 

Society of Testing and Materials in 

ASTM D6751 (incorporated by 

reference, see § 60.17), or biodiesel 

blends as defined by the American 

Society of Testing and Materials in 

ASTM D7467 (incorporated by 

reference, see § 60.17). 

Dry standard cubic foot (dscf) means 

the quantity of gas, free of uncombined 

water, that would occupy a volume of 

1 cubic foot at 293 Kelvin (20.0 °C) and 

101.325 kPa of pressure. 

Duct burner means a device that 

combusts fuel and that is placed in the 

exhaust duct from another source, such 

as a stationary combustion turbine, 

internal combustion engine, kiln, etc., to 

allow the firing of additional fuel to heat 

the exhaust gases. 

Emergency combustion turbine means 

any stationary combustion turbine 

which operates in an emergency 

situation. Examples include stationary 

combustion turbines used to produce 

power for critical networks or 

equipment, including power supplied to 

portions of a facility, when electric 

power from the local utility is 

interrupted, or stationary combustion 

turbines used to pump water in the case 

of fire or flood, etc. Emergency 

stationary combustion turbines do not 

include stationary combustion turbines 

used as peaking units at electric utilities 

or stationary combustion turbines at 

industrial facilities that typically 

operate at low capacity factors. 

Emergency combustion turbines may be 

operated for maintenance checks and 

readiness testing to retain their status as 

emergency combustion turbines, 

provided that the tests are required by 

the manufacturer, the vendor, or the 

insurance company associated with the 

turbine. Required testing of such units 

should be minimized, but there is no 

time limit on the use of emergency 

combustion turbines. 

Excess emissions means a specified 

averaging period over which either (1) 

the NOX or SO2 emissions rate are 

higher than the applicable emissions 

standard in § 60.4320 or § 60.4330; (2) 

the total sulfur content of the fuel being 

combusted in the affected facility or the 

SO2 emissions exceeds the standard 

specified in § 60.4330; or (3) the 

recorded value of a particular monitored 

parameter, including ration of water or 

steam to fuel, is outside the acceptable 

range specified in the parameter 

monitoring plan for the affected unit. 

Federally enforceable means all 

limitations and conditions that are 

enforceable by the Administrator or 

delegated authority, including the 

requirements of 40 CFR parts 60 and 61, 

requirements within any applicable 

State Implementation Plan, and any 

permit requirements established under 

40 CFR 52.21 or under 40 CFR 51.18 

and 51.24. 

Fuel oil means a fluid mixture of 

hydrocarbons that maintains a liquid 

state at ISO conditions. Additionally, 

fuel oil must meet the definition of 

either distillate oil or residual oil as 

defined by the American Society for 

Testing and Materials in ASTM D396 

(incorporated by reference, see § 60.17) 

or diesel fuel as defined by the 

American Society for Testing and 

Materials in ASTM D975 (incorporated 

by reference, see § 60.17). 

Gross useful energy output means: 

(1) For simple cycle and combined 

cycle combustion turbines, the gross 

useful work performed is the gross 

electrical or direct mechanical output 

from both the combustion turbine 

engine and any associated steam 

turbine(s). 

(2) For a CHP combustion turbine, the 

gross useful work performed is the gross 

electrical or direct mechanical output 

from both the combustion turbine 

engine and any associated steam 

turbine(s) plus any 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). 

(3) For a CHP combustion turbine 

where at least 20.0 percent of the total 

gross useful energy output consists of 

electric or direct mechanical output and 

20.0 percent of the total gross useful 

energy output consists of useful thermal 

output on an annual basis, the gross 

useful work performed is the gross 

electrical or direct mechanical output 

from both the combustion turbine 

engine and any associated steam 

turbine(s) divided by 0.95 plus any 

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). 

Heat recovery steam generating unit 

(HRSG) means a unit where the hot 

exhaust gases from the combustion 

turbine engine are routed in order to 

extract heat from the gases and generate 

useful output. Heat recovery steam 

generating units can be used with or 

without duct burners. 

Integrated gasification combined 

cycle electric utility steam generating 

unit (IGCC) means an electric utility 

steam generating unit that burns solidderived fuels in a combined-cycle 

combustion turbine. No solid fuel is 

directly combusted in the unit during 

operation. 

ISO conditions means 288 Kelvin (15 

°C), 60 percent relative humidity and 

101.325 kilopascals (kPa) pressure. 

Lean premix stationary combustion 

turbine means any stationary 

combustion turbine where the air and 

fuel are thoroughly mixed to form a lean 

mixture before delivery to the 

combustor. Mixing may occur before or 

in the combustion chamber. A lean 

premixed turbine may operate in 

diffusion flame mode during operating 

conditions such as startup and 

shutdown, extreme ambient 

temperature, or low or transient load. 

Low-Btu gas means biogas or any gas 

with a heating value of less than 26 

megajoules per standard cubic meter 

(MJ/scm) (700 Btu/scf). 

Natural gas means a fluid mixture of 

hydrocarbons, composed of at least 70 

percent methane by volume or that has 

a gross calorific value between 35 and 

41 MJ/scm (950 and 1,100 Btu/scf), that 

maintains a gaseous state under ISO 

conditions. In addition, natural gas 


TKELLEY on DSK3SPTVN1PROD with PROPOSALS
52580 Federal Register / Vol. 77, No. 168 / Wednesday, August 29, 2012 / Proposed Rules 

contains 460 mg/scm (20.0 gr/100 scf) or 

less of total sulfur. Finally, natural gas 

does not include any gaseous fuel 

produced in a process which might 

result in highly variable heating value. 

Noncontinental area means Guam, 

American Samoa, the Northern Mariana 

Islands, or offshore platforms. 

Offshore turbine means a stationary 

combustion turbine located on a 

platform in an ocean. 

Operating day means a 24-hour 

period between 12 midnight and the 

following midnight during which any 

fuel is combusted at any time in the 

unit. It is not necessary for fuel to be 

combusted continuously for the entire 

24-hour period. 

Operating hour means a clock hour 

during which any fuel is combusted in 

the affected unit. If the unit combusts 

fuel for the entire clock hour, it is 

considered to be a full operating hour. 

If the unit combusts fuel for only part 

of the clock hour, it is considered to be 

a partial operating hour. 

Out-of-control period means any 

period beginning with the quadrant 

corresponding to the completion of a 

daily calibration error, linearity check, 

or quality assurance audit that indicates 

that the instrument is not measuring 

and recording within the applicable 

performance specifications and ending 

with the quadrant corresponding to the 

completion of an additional calibration 

error, linearity check, or quality 

assurance audit following corrective 

action that demonstrates that the 

instrument is measuring and recording 

within the applicable performance 

specifications. 

Simple cycle combustion turbine 

means any stationary combustion 

turbine which does not recover heat 

from the combustion turbine engine 

exhaust gases for purposes other than 

enhancing the performance of the 

stationary combustion turbine itself. 

Solid fuel means any fuel that has a 

definite shape and volume, has no 

tendency to flow or disperse under 

moderate stress, and is not liquid or 

gaseous at ISO conditions. This 

includes, but is not limited to, coal, 

biomass, and pulverized solid fuels. 

Stationary combustion turbine means 

all equipment, including but not limited 

to the combustion turbine engine, the 

fuel, air, lubrication and exhaust gas 

systems, control systems, heat recovery 

system, steam turbine, fuel compressor, 

heater, and/or pump, post-combustion 

emission control technology, and any 

ancillary components and subcomponents. Stationary means that the 

combustion turbine is not self propelled 

or intended to be propelled while 

performing its function. It may, 

however, be mounted on a vehicle for 

portability. 

Standard cubic foot (scf) means the 

quantity of gas that would occupy a 

volume of 1 cubic foot at 293 Kelvin 

(20.0 °C) and 101.325 kPa of pressure. 

Standard cubic meter (scm) means the 

quantity of gas that would occupy a 

volume of 1 cubic meter at 293 Kelvin 

(20.0 °C) and 101.325 kPa of pressure. 

Turbine tuning means planned 

maintenance of a lean premix 

combustion turbine engine involving 

adjustment of the operating 

configuration to maintain proper 

combustion dynamics. Turbine tuning is 

limited to 30 hours annually. 

Useful thermal output means the 

thermal energy made available for 

processes and applications other than 

electrical or mechanical generation or to 

enhance the performance of the 

stationary combustion turbine (i.e., the 

thermal energy made available for use in 

any industrial or commercial process or 

used in any heating application). Useful 

thermal output for this subpart is 

measured relative to the enthalpy of the 

thermal output in its most prevalent 

form at ISO conditions (e.g., liquid 

water). 

TABLE 1 TO SUBPART KKKK OF PART 60—NITROGEN OXIDE EMISSION STANDARDS FOR STATIONARY COMBUSTION

TURBINES

[All numerical values have two significant figures] 

Combustion turbine type 

Combustion turbine heat 

input at base load rating 

(HHV) 

NOX emissions standard 

Alternate NOX

emissions 

standard in 

ppm at 15 

percent O2

New turbine firing natural gas, electric generating ≤ 15 MW (50 MMBtu/h) 67 ng/J (0.16 lb/MMBtu) heat input or 290 ng/J 

of gross energy output (2.3 lb/MWh).

42 

New turbine firing natural gas, mechanical drive ≤ 15 MW (50 MMBtu/h) 160 ng/J (0.37 lb/MMBtu) heat input or 690 ng/J 

of gross energy output (5.5 lb/MWh).

100 

New turbine firing natural gas ............................... > 15 MW (50 MMBtu/h) 

and ≤ 250 MW (850 

MMBtu/h).

40 ng/J (0.093 lb/MMBtu) heat input or 150 ng/J 

of gross energy output (1.2 lb/MWh).

25 

New, modified, or reconstructed turbine firing natural gas.> 250 MW (850 

MMBtuh).

24 ng/J (0.056 lb/MMBtu) heat input or 54 ng/J 

of gross energy output (0.43 lb/MWh).

15 

New turbine firing fuels other than natural gas, 

electric generating.

≤ 15 MW (50 MMBtu/h) 160 ng/J (0.38 lb/MMBtu) heat input or 710 ng/J 

of gross energy output (5.6 lb/MWh).

96 

New turbine firing fuels other than natural gas, 

mechanical drive.

≤ 15 MW (50 MMBtu/h) 250 ng/J (0.59 lb/MMBtu) heat input or 1,100 ng/ 

J of gross energy output (8.7 lb/MWh).

150 

New turbine firing fuels other than natural gas .... > 15 MW (50 MMBtu/h) 

and ≤ 250 MW (850 

MMBtu/h).

120 ng/J (0.29 lb/MMBtu) heat input or 470 ng/J 

of gross energy output (3.7 lb/MWh).

74 

New, modified, or reconstructed turbine firing 

fuels other than natural gas.

> 250 MW (850 MMBtu/ 

h).

73 ng/J (0.17 lb/MMBtu) heat input or 160 ng/J 

of gross energy output (1.3 lb/MWh).

42 

Modified or reconstructed turbine ......................... ≤ 15 MW (50 MMBtu/h) 250 ng/J (0.59 lb/MMBtu) heat input or 1,100 ng/ 

J of gross energy output (8.7 lb/MWh).

150 

Modified or reconstructed turbine firing natural 

gas.

> 15 MW (50 MMBtu/h) 

and ≤ 250 MW (850 

MMBtu/h).

67 ng/J (0.16 lb/MMBtu) heat input or 250 ng/J 

of gross energy output (2.0 lb/MWh).

42 

Modified or reconstructed turbine firing fuels 

other than natural gas.

> 15 MW (50 MMBtu/h) 

and ≤ 250 MW (850 

MMBtu/h).

160 ng/J (0.38 lb/MMBtu) heat input or 600 ng/J 

of gross energy output (4.8 lb/MWh).

96 


TKELLEY on DSK3SPTVN1PROD with PROPOSALS
Federal Register / Vol. 77, No. 168 / Wednesday, August 29, 2012 / Proposed Rules 52581 

TABLE 1 TO SUBPART KKKK OF PART 60—NITROGEN OXIDE EMISSION STANDARDS FOR STATIONARY COMBUSTION

TURBINES—Continued 

[All numerical values have two significant figures] 

Combustion turbine type 

Combustion turbine heat 

input at base load rating 

(HHV) 

NOX emissions standard 

Alternate NOX

emissions 

standard in 

ppm at 15 

percent O2

Turbines located north of the Arctic Circle (latitude 66.5 degrees north), turbines operating at 

less than 75 percent of the base load rating, 

turbines operated during periods of turbine tuning, startup, or shutdown, modified and reconstructed offshore turbines, or turbines operating at temperatures less than minus 17 °C.

≤ 100 MW (340 MMBtu/ 

h).

250 ng/J (0.59 lb/MMBtu) heat input or 1,100 ng/ 

J of gross energy output (8.7 lb/MWh).

150 

Turbines located north of the Arctic Circle (latitude 66.5 degrees north), turbines operating at 

less than 75 percent of the base load rating, 

turbines operated during periods of turbine tuning, startup, or shutdown, modified and reconstructed offshore turbines, or turbines operating at temperatures less than minus 17 °C.

> 100 MW (340 MMBtu/ 

h).

160 ng/J (0.38 lb/MMBtu) heat input or 610 ng/J 

of gross energy output (4.8 lb/MWh).

96 

Heat recovery units operating independent of the 

combustion turbine engine.

All sizes ......................... 86 ng/J (0.20 lb/MMBtu) heat input or 110 ng/J 

of gross energy output (0.90 lb/MWh).

50 

[FR Doc. 2012–20524 Filed 8–28–12; 8:45 am] 

BILLING CODE 6560–50–P 


TKELLEY on DSK3SPTVN1PROD with PROPOSALS