From: Wayland, Robertj [mailto:Wayland.Robertj@epa.gov] 

Sent: Friday, April 18, 2014 5:35 PM 

To: Higgins, Cortney 

Cc: Culligan, Kevin; Tsirigotis, Peter; Srivastava, Ravi 

Subject: RIA Briefing and Reg Text for 111(b) Rule 

Cortney - 

Attached to this email, please find the PowerPoint briefing for Monday's discussion of the RIA, and 

the regulatory text TSD for the 111(b) mods/recon package. If you have any questions, please free 

to give me a call on my cell (919-306-2290). Hope you have a nice Easter weekend - talk with you 

on Monday morning. 

bob 

Robert J. Wayland, Ph.D. 

Leader, Energy Strategies Group 

U.S. Environmental Protection Agency 

Office of Air Quality Planning and Standards 

Sector Policies and Programs Division 

Mail Code D243-01 

Research Triangle Park, North Carolina 27709 

 

Office: (919) 541-1045 

Cell: (919) 306-2290 

Fax: (919) 541-5450 

 

Email: wayland.robertj@epa.gov 

 

***************************************** 

DRAFT/Deliberative Document - FOIA EXEMPT 

***************************************** 

<< EGU GHG RIA Briefing 04_18_14 OMB.pptx >> 

<< Reg Text TSD to OMB 18 April 2014.docx >> 
Deliberative – Do Not Cite or Quote 

Greenhouse Gas 

Electric Generating Unit Existing/ Mo

Reconstructed Source Proposa

Regulatory Impact Analysis (RIA

Briefing for Interagency Review Group

April 21, 2014
Deliberative – Do Not Cite or Quote 

Outline► RIA overview► Control strategies, emission reductions, and costs 

► Control strategies► Emission reductions► Costs► Economic Impacts for the electricity sector and fuel sec

► Benefits► Net benefits► Upstream methane emissions► Economic impacts for sectors outside the electricity m

industrial electricity customers)

► Employment impacts► Statutory and Executive Order analyses► Modified and reconstructed source standards
Deliberative – Do Not Cite or Quote 

RIA Overview

► The RIA presents illustrative benefits, costs and economic impact

states may take to comply with the greenhouse gas electric gener(GHG EGU) emission guidelines.

► Base Case

► Include relevant promulgated regulations (MATS, CAIR, etc.) and othe

such as regional haze, but does not include NAAQS or the replacemeState Rule.

► Two regulatory alternatives are analyzed: 

► Option 1 

• Proposed option – more stringent • Compliance by 2030 

► Option 2 

• Regulatory alternative – less stringent• Compliance by 2025

► Two compliance approaches are analyzed for each option

• Regional compliance - assumes states collaborate• State compliance - assumes states comply on a state specific ba

► Three analysis years – 2020, 2025, and 2030. All estimates are sh► Addresses relevant Executive Orders and statutory requirements 

12866, EO 13563, small business impacts, unfunded mandates, a

► One RIA for existing source/modified & reconstructed source rulem
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Control Strategies and Costs

► Modeling is done using IPM and other tools, to estim

emission reductions and costs of the 111(d) guideline potential alternatives)

► Similar in scope to all past power sector air regulations

added complexities unique to 111(d)

► Detailed power sector impacts from IPM are included 

(e.g., coal and gas markets, electricity prices, generaretirements, etc.)
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Building Block Technologies Translated to State 

Technology/Building Block Option 1 O1. Heat rate improvement (Avg. 

Reduction for Coal) 6% 

2. Dispatch to existing and underconstruction NGCC Utilization of NGCC up to 70% capacity factor Utilizat

up to 6

3. Dispatch to new clean electric 

generation

Includes nuclear under construction 

moderate deployment of new renewa

4. Demand-side Energy Efficiency 

(% reduction in demand from BAU MWh 

sales)

3.0% / 10.7%

(2020 / 2030)

2.4

(202
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1,5001,7001,9002,1002,3002,5002,700

2000 2005 2010 2015 2020 202

Base CaseOption 1 ‐ RegionalOption 1 ‐ StateOption 2 ‐ RegionalOption 2 ‐ State

Power Sector CO2 Emissions (million me

Note: Historical data from EPA’s GHG inventory, projections from IPM.

CO2 Emissions (MM Tonnes) CO2 Emissions Reductions: from 2005 (MM Tonnes) CO2 Emiss

Percent C

2020 2025 2030 2020 2025 2030 2020 

Base Case 2,161 2,231 2,256 273 203 178 11% 

Option 1 Regional 1,790 1,730 1,711 644 704 723 26% 

Option 1 State 1,777 1,724 1,701 657 710 733 27% 

Option 2 Regional 1,878 1,862 1,903 556 572 531 23% 

Option 2 State 1,866 1,855 1,882 568 579 552 23% 
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► Annual costs (billions of 2011$)► National average retail electricity prices

► Option 1: Roughly 6-7% increase in 2020 and 2-3% in 2► Option 2: Roughly 3-4% increase in 2020 and 1-2% in 2

► National average impact on electric bills

► Option 1: Roughly 3% increase in 2020, but 9% lower b► Option 2: Roughly 1-2% increase in 2020, but 7% lower 

Economic Impacts (vs. Base Case)

2020 20

Option 1 – Regional 5.4 7Option 1 – State 7.4 8Option 2 – Regional 4.2 1Option 2 – State 5.4 3
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► Retirements, by 2020

► Option 1: 50 GW of additional coal retirements, up to 17 GW O/G ste► Option 2: 30 GW of coal, 12 GW of O/G steam

► Coal Capacity (Net Summer: 310 GW existing in 2012, about 240 GW in 2

► Option 1: 191 GW to 198 GW remaining in service (2020-2030)► Option 2: 208 GW to 214 GW remaining in service (2020-2030)

► Capacity Changes

► Option 1: 20-22 GW additional NGCC by 2020, but 32-35 GW less th

2030, and 8 to 12 GW of new renewables

► Option 2: 9 to 14 GW of additional NGCC by 2020, 26 to 31 GW less 

by 2030, and 6 to 9 GW of new renewables

► Coal Production (national)

► Option 1: 25% to 27% lower production and 16% to 18% decrease in 

2030)

► Option 2: 19% to 21% lower production and roughly 14% decrease in 

2030)

► Natural gas price (delivered, power)

► Option 1: Roughly 9% to 12% increase in 2020 and negligible change► Option 2: Roughly 7% to 8% increase in 2020, and negligible change

Other Impacts (vs. Base Case)
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Overview of Benefits Analysis► Climate benefits of CO2 reductions estimated using th

recent estimates of the global Social Cost of Carbon (

► Health co-benefits estimated using regional benefit-pe

estimates derived from EGU sector modeling publisheet al. (2012)

► PM2.5 and precursors (SO2, NOx, directly emitted PM2.5

• Same epidemiology studies and census data as 2012 PM 

► Ozone 

• Same epidemiology studies as 2010 Ozone NAAQS RIA• Assumes impacts from NOx alone because little VOC from 

► Qualitative benefits and co-benefits

► Climate impacts of non-CO2 pollutants► Health effects from direct exposure to NO2, SO2, and HA► Visibility impairment► Ecosystem effects
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Monetized Benefits for Options 1 and 2

Option and Compliance

Approach

National Emission Reductions from Base Case Monetiz

(billion

2020 2025 2030 2020 

Option 1 

State

Climate Benefits* CO2: 383 MMT CO2: 506 MMT CO2: 555 MMT $18 ($4.9-$52) 

($7

Health Cobenefits** SO2: 335,000 tons NOX: 367,000 tons SO2: 425,000 tons NOX: 436,000 tons SO2: 471,000 tons NOX: 428,000 tons $15 to $36 $2

Option 1 

Regional

Climate Benefits* CO2: 371 MMT CO2: 501 MMT CO2: 545 MMT $17 ($4.7-$51) 

($7

Health Cobenefits** SO2: 292,000 tons NOX: 345,000 tons SO2: 395,000 tons NOX :421,000 tons SO2: 424,000 tons NOX: 407,000 tons $15 to $34 $2

Option 2 

State

Climate Benefits* CO2: 295 MMT CO2: 376 MMT CO2: 373 MMT $14 ($3.8 -$40) 

($5

Health Cobenefits** SO2: 267,000 tons NOX: 281,000 tons SO2: 327,000 tons NOX: 317,000 tons SO2: 321,000 tons NOX: 274,000 tons $12 to $29 $1

Option 2 

Regional

Climate Benefits* CO2: 283 MMT CO2: 368 MMT CO2: 353 MMT $13 ($3.6-$39) 

($5

Health Cobenefits** SO2: 244,000 tons NOX: 268,000 tons SO2: 297,000 tons NOX: 309,000 tons SO2: 287,000 tons NOX: 252,000 tons $12 to $28 $1

* Climate benefits are calculated with average SCC at a 3% discount rate, the value deemed central by the ingroup; climate benefits using additional SCC estimates (avg. SCC at 5% and 2.5%; 95th percentile at 3%) are 

in parentheses; climate benefits reflect only changes in CO2 emissions.

** Health co-benefits are shown at a 3% discount rate and calculated using regional benefit-per-ton estimates

discount rate are approximately 9% lower; co-benefits from reductions in directly emitted particles are not yet 

benefits reflect reduced exposure to ambient PM2.5 from emission reductions of SO2 and NOx and reduced e

ozone from emission reductions of ozone-season NOx; range reflects different epidemiology studies; monetizinclude additional co-benefit categories, including direct exposure to SO2, NO2, or HAP; ecosystem effects; o
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Preliminary Net Benefits

Option and Compliance

Approach

Net Benefits (billions of 2011$, 3% discount rate

2020 2025 

Option 1 State $26 to $46 $41 to $70 

Option 1 Regional $26 to $46 $42 to $70 

Option 2 State $20 to $37 $30 to $52 

Option 2 Regional $21 to $37 $30 to $51 

* Includes central climate benefits and health co-benefits at a 3% discount rate; benefits estima

additional discount rates would show a broader range; benefits shown here are rounded to two 

so net benefits may not sum from previous slides

•Net benefits are positive for all combinations of costs and total mone(climate plus health)•Climate benefits alone often exceed costs

•Climate benefits alone exceed costs using a 3% discount rate focompliance approaches for both options in all analysis years•Climate benefits alone exceed costs using any discount rate for compliance approaches for both options in 2025 and 2030

•Option 1 net benefits exceed Option 2 in all years analyzed. Net benroughly equivalent between state and regional approaches within the 
Deliberative – Do Not Cite or Quote 

Changes in Upstream Methane Emissions► RIA presents supplementary analysis of potential implications for coal and 

sector methane emissions in appendix to Cost, Economic, and Energy Im

► IPM results indicate decreases in coal production and smaller increases o

natural gas production (depending on year) as a result of the compliance 

► IPM coal and natural gas production results input into emissions projectio

developed for EPA submission to the US Climate Action Report to estimatupstream methane emissions and CO2 emissions from natural gas flaring

► Upstream defined in this analysis as being from the mine or well to the po► Overall results:

► Net reduction in upstream methane emissions and CO2 emissions fro► Magnitude is small relative to the emissions changes at power plants

Change in upstream methane emissions and CO2 emissions

from natural gas flaring (MM Tonnes CO2‐eq.) 2020 2025 

Option 1‐ Regional ‐9.9 ‐16.0 

Option 1 ‐ State ‐10.6 ‐16.4 

Option 2 ‐ Regional ‐7.4 ‐11.4 

Option 2 ‐ State ‐7.7 ‐11.8 
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Impacts Outside the EGU Sector► Addresses the ripple effect of energy price changes (e

natural gas, coal) through the economy for sectors otthe EGU sector

► The best way to analyze impacts on the economy is b

dynamic computable general equilibrium (CGE) modeadvice from the Science Advisory Board (SAB) panel specifically to address the subject of economy-wide mwill not be available in time for this proposal

► This RIA only discusses these impacts qualitatively an

emphasizes the flexibility states will have to mitigate inecessary
Deliberative – Do Not Cite or Quote 

GHG Existing Source Employment ImpacAnalysis Overview► The RIA will primarily discuss the employment impacts for t

guidelines based on the four building blocks.

► Qualitative

• Peer reviewed literature 

– “Economic theory predicts that the total effect of an environ

on labor demand in regulated sectors is not necessarily pos

– Peer-reviewed econometric studies suggest whether positiv

impacts have been small and have not affected employmensectors in a significant way.” 

– There is evidence suggesting environmental regulation may 

supply and productivity.

• Historical trends in employment in the power, coal and natural ga• Recent historical trends in clean energy employment

► Quantitative

• Partial potential impacts of supply side and demand-side employ

– Job estimates in the EGU, coal and natural gas sectors bas

engineering-cost information for a subset of possible emploprovided (similar to MATS analysis)

– Demand-side energy efficiency employment estimates base

Bureau of Labor Statistics and the Annual Survey of Manufa
Deliberative – Do Not Cite or Quote 

Employment Impacts - Regional Compliance Ap

Category Option 1 Opt

2020 2025 2030 2020 2

Supply Side – Quantified Impacts

Heat Rate Improvement 32,900 0 0 33,900 Boilermakers and General Construction 22,800 0 0 23,600 Engineering and Management 6,000 0 0 6,200 Equipment-related 2,900 0 0 3,000 Material-related 1,100 0 0 1,100 New Capacity Construction 24,200 -33,300 -37,000 10,600 Renewables 17,500 -4,700 -2,100 9,500 Natural Gas 6,700 -28,600 -34,900 1,100 Operation and Maintenance -22,900 -23,800 -23,700 -15,300 

Changes in Gas 2,300 -600 -3,400 1,000 Retired Coal -22,600 -20,800 -18,200 -14,600 Retired Oil and Gas -2,600 -2,400 -2,100 -1,700 Fuel Extraction -8,800 -14,900 -19,200 -6,600 Coal -13,700 -17,000 -16,600 10,900 Natural Gas 4,900 2,100 -2,600 4,300 

Supply Side Employment Impacts –

Total (job-years) 25,400 -72,000 -79,000 22,600 

Demand Side – Quantified Impacts*

Energy Efficiency Employment 

Impacts –Total (jobs)* 78,800 112,000 111,800 57,000 

Unquantified - Other Employment Impacts

• Other additional direct and indirectly related jobs in the man

materials sectors.

• Additional upstream and downstream effects of EE investm

demand for steel, increased spending in non-energy catego

*Estimates may change pending additional analysis.

Estimates may not sum due to rounding.
Deliberative – Do Not Cite or Quote 

Employment Impacts - State Compliance Approa

Category Option 1 Opt

2020 2025 2030 2020 2

Supply Side – Quantified Impacts

Heat Rate Improvement 32,200 0 0 30,800 Boilermakers and General Construction 22,400 0 0 21,400 Engineering and Management 5,900 0 0 5,700 Equipment-related 2,900 0 0 2,800 Material-related 1,000 0 0 1000 New Capacity Construction 21,900 -38,000 -36,100 15,800 Renewables 12,200 -8,900 -2,200 8,000 Natural Gas 9,700 -29,100 -34,000 7,800 Operation and Maintenance -24,100 -25,300 -24,900 -16,800 

Changes in Gas 2,500 -500 -3,200 1,500 Retired Coal -24,000 -22,500 -19,700 -16,400 Retired Oil and Gas -2,600 -2,300 -2,000 -1,900 Fuel Extraction -8,300 -14,600 -19,400 -6,500 Coal -14,300 -17,800 -18,000 -11,500 Natural Gas 6,000 3,200 -1,400 5,000 

Supply Side Employment Impacts –

Total (job-years) 21,700 -77,900 -80,400 23,300 

Demand Side – Quantified Impacts*

Energy Efficiency Employment 

Impacts –Total (jobs)* 78,800 112,000 111,800 57,000 

Unquantified - Other Employment Impacts

• Other additional direct and indirectly related jobs in the man

materials sectors.

• Additional upstream and downstream effects of EE investm

demand for steel, increased spending in non-energy catego

*Estimates may change pending additional analysis.

Estimates may not sum due to rounding.
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Statutory and Executive Orders► Substantial outreach was undertaken with small entities, local

tribal governments, the business community and the public

► Proposed guidelines do not impose requirements on small ent

not impose a significant economic impact on a substantial numentities, because states establish standards on existing sourceguidelines are promulgated

► Proposed guidelines do not have federalism implications (sub

compliance costs on state or local governments) and do not cfederal mandate for state, local or tribal governments or the pr(UMRA), because the guidelines do not impose any direct comrequirements on regulated entities

► Action is a “significant energy action”► Proposed guidelines will reduce CO2, SO2, NOx, PM2.5, HCl a

emissions. Generally considered to be beneficial to all commstates will make the ultimate compliance decisions

► Paperwork Reduction Act analysis to estimate monitoring, rep

recordkeeping costs is still in progress
Deliberative – Do Not Cite or Quote 

Modified and Reconstructed Source Stan► Based on historical information, the EPA anticipates few, if 

units will trigger the reconstruction or modification provisionresult, we expect there would be minimal emission reductiobenefits associated with the proposed standards.

► Because there have been a few units that have notified the 

modifications in the past, the RIA presents an illustrative ancosts and benefits for a hypothetical unit if it were to trigger modification provision.

► We estimate that a 500 MW coal unit could achieve a 6% effic

improvement for an annualized cost of $8.3 million.

► These efficiency improvements would result in an annual fuel 

$5.6 million.

► These efficiency improvements would result in reductions in C

and PM2.5 emissions.

• For a 6% efficiency improvement, EPA estimates the combined c

from reductions in CO2 and health co-benefits from reductions in 

PM2.5 total $27 to $49 million (2011$) at a 3 percent discount rate 

reductions in 2025.
Page 1 of 45

MEMORANDUM 

From: Office of Air Quality Planning and Standards 

 U.S. Environmental Protection Agency 

To: EGU NSPS Docket (EPA-HQ-OAR-2013-0603) 

Date: June, 2014 

Subject: Amended Regulatory Text 

Amended Regulatory Text 

On January 8, 2014, the EPA proposed amendments (79 FR 1430) to the regulatory text of 

subparts Da and KKKK to include greenhouse gas (GHG) standards for new electric generating 

units (EGUs). As an alternative to amending proposed subparts Da and KKKK, the EPA coproposed creating a new subpart TTTT to include the proposed GHG standards. Since those 

amendments have not been finalized we would have to reprint the January 8, 2014, amendments 

in this rulemaking and add the amendments in this proposal to the previous amendments. 

However, that could complicate the ability of the public to identify the proposed amendments 

included in this proposal. Therefore, to facilitate understanding the amendments being proposed 

in this proposal, the following document uses track changes to demonstrate the GHG standards 

for the proposed standards for modified and reconstructed EGUs on top of the existing proposed 

amendments from January 8, 2014. 

In addition, in docket item EPA-HQ-OAR-2013-0495-0062 of the January 8, 2014, proposal, the 

EPA elaborated upon the request for comment included in the preamble on whether the general 

applicability of the proposed standards should be broadened and based on design characteristics 

instead of design characteristics and operating parameters. Under this approach, a GHG emission 

standard would apply during periods when certain conditions are met and no numerical GHG 

emission standard would apply during periods when one or more of those conditions are not met. 

In other words, although there would be no numerical emission limit, the facility would remain 

subject to the standard of performance. The track changes of the proposed amendments in this 

proposal include this expanded applicability approach. 

We intend to finalize the proposed amendments for modified and reconstructed EGUs following 

the approach finalized in the new source proposal published on January 8, 2013. For example, if 

the new source requirements are included in subparts Da and KKKK and use the applicability 

described in detail in docket item EPA-HQ-OAR-2013-0495-0062, the proposed requirements in 

this proposal would be added to those amendments. 

 
Page 2 of 45

Subpart Da-— Standards of Performance for Electric Utility Steam Generating Units 

2. Section 60.46Da is added to read as follows: 

§60.46Da Standards for carbon dioxide (CO2). 

(a) Your affected facility is subject to this section if construction commenced after 

January 8, 2014 or if modification or reconstruction commenced after [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER], and the affected facility meets the conditions 

specified in paragraphs (a)(1) and (a)(2) of this section, except as specified in paragraph (b) of 

this section. 

(1) The affected facility combusts fossil fuel for more than 10.0 percent of the heat input 

during any 3 consecutive calendar years. 

(2) The affected facility net-electric sales consist ofsupplies more than one-third of its 

potential electric output and more than 219,000 MWh net-electric output to a utility power 

distribution system for sale on an annual basis. 

(b) The following EGUs are not subject to this section: 

(1) The proposed Wolverine EGU project described in Permit to Install No. 317-07 

issued by the Michigan Department of Environmental Quality, Air Quality Division, effective 

June 29, 2011 (as revised July 12, 2011). 

(2) The proposed Washington County EGU project described in Air Quality Permit No. 

4911-303-0051-P-01-0 issued by the Georgia Department of Natural Resources, Environmental 

Protection Division, Air Protection Branch, effective April 8, 2010, provided that construction 

had not commenced for NSPS purposes as of January 8, 2014. 

(3) The proposed Holcomb EGU project described in Air Emission Source Construction 

Permit 0550023 issued by the Kansas Department of Health and Environment, Division of 

Environment, effective December 16, 2010, provided that construction had not commenced for 

NSPS purposes as of January 8, 2014. 

(c) As owner or operator of an affected facility subject to this section, you shall not cause 

to be discharged into the atmosphere from the affected facility any gases that contain CO2 in 

excess of the emissions limitation specified in either this paragraphs (c)(1) or (c)(2) of this 

section. 

(1) As owner or operator of an affected facility for which construction commenced after 

January 8, 2014, you shall not cause to be discharged into the atmosphere from the affected 

facility any gases that contain CO2 in excess of the emissions limit specified in paragraph 

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

(i) 500 kilograms (kg) of CO2 per megawatt-hour (MWh) of gross energy output (1,100 

lb CO2/MWh) on a 12-operating month rolling average basis; or 

(ii2) 480 kg of CO2 per MWh of gross energy output (1,050 lb CO2/MWh) on an 84-

operating month rolling average basis.

(2) As owner or operator of an affected facility for which reconstruction commenced 

after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], you shall not 

Comment [FC1]: Changing terminology to “netelectric sales” so “net-electric output” can be used in 

the definition of “net energy output” when 

determining the emission rate. 

Comment [FC2]: Use consistent terminology – 

either “limit” or “standard” 

Comment [FC3]: For references purposes, in 

Table 4 of the January 8, 2014, proposal (79 FR 

1430) the approximate net output based standard that 

corresponds to an 1,100 lb CO2/MWh-gross 

standard is 1,400 lb CO2/MWh-net 
Page 3 of 45

cause to be discharged into the atmosphere from the affected facility any gases that contain CO2

in excess of the emissions limit specified in paragraph (c)(2)(i) or (c)(2)(ii) of this section. 

(i) If the design rated capacity of your affected facility is 590 MW (2,000 MMBtu/h) or 

less, 950 kg CO2/MWh of net energy output (2,100 lb CO2/MWh) on a 12-operating month 

rolling average basis; or 

(ii) If the design rated capacity of your affected facility is greater than 590 MW (2,000 

MMBtu/h), then 820 kg CO2/MWh of net energy output (1,900 lb CO2/MWh) on a 12-operating 

month rolling average basis. 

(3) As owner or operator of an affected facility for which modification commenced after 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], you shall not cause to 

be discharged into the atmosphere from the affected facility any gases that contain CO2 in excess 

of the emissions limit specified in paragraph (c)(3)(i) or (c)(3)(ii) of this section. 

(i) If the facility is not subject to an approved CAA section 111(d) plan (state or federal), 

a CO2 emissions limit specified in paragraph (c)(3)(i)(A), (c)(3)(i)(B), or (c)(3)(i)(C) of this 

section. 

(A) a site-specific12-operating month rolling average CO2 emission limit calculated as 2 

percent lower than (i.e., 98 percent) the best demonstrated annual historical operating 

performance for the affected facility using historical CO2 emissions data for the calendar years 

2002 through the most recent full calendar year the affected facility was operating prior to the 

modification using either recorded net output emission rate data or gross electrical output and 

CO2 emissions data as reported under part 75 of this chapter. If incomplete or no data has been 

submitted under part 75 of this chapter, the Administrator or delegated authority shall approve 

the use of alternate data sources. The equivalent net output-based standard shall be calculated 

from gross output-based data assuming a 7.5 percent auxiliary (i.e., parasitic) load (i.e., the best 

annual value is divided by 0.925); 

(B) If the design rated capacity of your affected facility is 590 MW (2,000 MMBtu/h) or 

less, 950 kg CO2/MWh of net energy output (2,100 lb CO2/MWh) on a 12-operating month 

rolling average basis; or 

(C) If the design rated capacity of your affected facility is greater than 590 MW (2,000 

MMBtu/h), 820 kg CO2/MWh of net energy output (1,900 lb CO2/MWh) on a 12-operating 

month rolling average basis. 

(ii) If the facility is subject to an approved CAA section 111(d) plan (state or federal), a 

site-specific 12-operating month rolling average CO2 emission limit determined by the CAA 

section 111(d) implementing authority based on the affected facility performing an energy 

assessment by an energy professional or engineer that have expertise in evaluating energy 

systems to identify applicable energy efficiency projects that you will implement at the affected 

facility to improve the affected facility’s operating performance. You must maintain a copy of 

the most recent energy assessment report. The energy assessment must include at a minimum the 

elements in paragraphs (c)(3)(ii)(A) through (c)(3)(ii)(C) of this section. 

(A) A visual inspection of the facility to identify steam leaks or other sources of reduced 

efficiency, 

Comment [FC4]: Since facility is not subject to 

111(d) there is no CAA section 111(d) authority. 
Page 4 of 45

(B) A review of available engineering plans and facility operation and maintenance 

procedures and logs, and 

(C) A comprehensive report detailing the ways to improve efficiency, the cost of specific 

improvements, benefits, and the time frame for recouping those investments. 

(d) You must make compliance determinations at the end of each operating month, as 

provided in paragraphs (d)(1) and (d)(2) of this section. For the purpose of this section, operating 

month means a calendar month during which any fossil fuel is combusted in the affected facility. 

(1) If you elect toare complying with the a 12-operating month CO2 emissions limitation 

in paragraph (c)(1) of this section, you must determine compliance monthly by calculating the 

average CO2 emissions rate for the affected facility at the end of each 12-operating month period 

that includes, as the last month, the month for which you are determining compliance. 

(2) If you elect toare complying with thean 84-operating month CO2 emissions limitation 

in paragraph (c)(2) of this section, you must determine compliance monthly by calculating the 

average CO2 emissions rate for the affected facility at the end of each 84-operating month period 

that includes, as the last month, the month for which you are determining compliance. 

(e) You must conduct an initial compliance determination with the CO2 emissions 

limitation for your affected facility within 30 days after accumulating the required number of 

operating months for the compliance period with which you have elected to comply (i.e., 12-

operating months or 84-operating months). The first operating month included in this compliance 

period is the month in which emissions reporting is required to begin under § 75.64(a) of this 

chapter. 

(f) You must monitor and collect data to demonstrate compliance with the CO2 emissions 

limitation according to the requirements in paragraphs (f)(1) through (4) of this section. 

(1) You must prepare a monitoring plan in accordance with the applicable provisions in § 

75.53(g) and (h) of this chapter. 

(2) You must measure the hourly CO2 mass emissions from each affected facility using 

the procedures in paragraphs (f)(2)(i) through (vii) of this section, except as provided in 

paragraph (f)(3) of this section. 

(i) You must install, certify, operate, maintain, and calibrate a CO2 continuous emission 

monitoring system (CEMS) to directly measure and record CO2 concentrations in your affected 

facility’s exhaust gases that are emitted to the atmosphere and an exhaust gas flow rate 

monitoring system according to §75.10(a)(3)(i) of this chapter. If you measure CO2

concentration on a dry basis, you must also install, certify, operate, maintain, and calibrate a 

continuous moisture monitoring system, according to §75.11(b) of this chapter. 

(ii) For each monitoring system used to determine the CO2 mass emissions, you must 

meet the applicable certification and quality assurance procedures in §75.20 of this chapter and 

Appendices B and D to part 75 of this chapter. 

(iii) You must use a laser device to measure the dimensions of each exhaust gas stack or 

duct at the flow monitor and the reference method sampling locations prior to the initial setup 

(characterization) of the flow monitor. For circular stacks, you must make measurements of the 

diameter at three or more distinct locations and average the results. For rectangular stacks or 

ducts, you must make measurements of each dimension (i.e., depth and width) at three or more 
Page 5 of 45

distinct locations and average the results. If the flow rate monitor or reference method sampling 

site is relocated, you must repeat these measurements at the new location. 

(iv) You can only use unadjusted exhaust gas volumetric flow rates to determine the 

hourly CO2 mass emissions from the affected facility; you must not apply the bias adjustment 

factors described in section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow 

rate data. 

(v) If you choose to use Method 2 in Appendix A-1 to this part to perform the required 

relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a 

calibrated Type-S pitot tube or pitot tube assembly. You must not use the default Type-S pitot 

tube coefficient. 

(vi) If two or more affected facilities share a common exhaust gas stack and are subject to 

the same CO2 emissions limitation in paragraph (c) of this section, you may monitor the hourly 

CO2 mass emissions at the common exhaust gas stack rather than monitoring each affected 

facility separately. 

(vii) If the exhaust gases from the affected facilities are emitted to the atmosphere 

through multiple stacks (or if the exhaust gases are routed to a common stack through multiple 

ducts and you choose to monitor in the ducts), you must monitor the hourly CO2 mass emissions 

and the “stack operating time” (as defined in § 72.2 of this chapter) at each stack or duct 

separately. 

(3) As an alternative to complying with paragraph (f)(2) of this section, for affected 

facilities that do not combust any solid fuel, you may determine the hourly CO2 mass emissions 

by using Equation G-4 in Appendix G to part 75 of this chapter according to the requirements 

specified in paragraphs (f)(3)(i) and (f)(3)(ii) of this section. 

(i) You must implement the applicable procedures in Appendix D to part 75 of this 

chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of 

fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel 

combusted. 

(ii) You may determine site-specific carbon-based F-factors (Fc) using Equation F-7b in 

section 3.3.6 of Appendix F to part 75 of this chapter, and you may use these Fc values in the 

emissions calculations instead of using the default Fc values in the Equation G-4 nomenclature. 

(4) You must install, calibrate, maintain, and operate a sufficient number of watt meters 

to continuously measure and record the gross or net electric output from the affected facility,.

Measurements must be performed using 0.2 class electricity metering instrumentation and 

calibration procedures as specified under ANSI Standards No. C12.20.and yYou must also meet 

the requirements specified in paragraphs (f)(4)(i) and (ii) of this section, as applicable. 

(i) If your affected facility is a combined heat and power unit as defined in § 60.42Da, 

you must also install, calibrate, maintain, and operate meters to continuously determine and 

record the total useful recovered thermal energy. For process steam applications, you must 

install, calibrate, maintain, and operate meters to continuously determine and record steam flow 

rate, temperature, and pressure. If your affected facility has a direct mechanical drive application, 

you must submit a plan to the Administrator or delegated authority for approval of how gross or 
Page 6 of 45

net energy output will be determined. Your plan shall ensure that you install, calibrate, maintain, 

and operate meters to continuously determine and record each component of the determination. 

(ii) If two or more affected facilities have steam generating units that serve a common 

electric generator, you must apportion the combined hourly gross or net electric output to each 

individual affected facility using a plan approved by the Administrator (e.g., using steam load or 

heat input to each affected facility). Your plan shall ensure that you install, calibrate, maintain, 

and operate meters to continuously determine and record each component of the determination. 

(g) You must demonstrate compliance with the CO2 emissions limitation using the 

procedures specified in paragraphs (g)(1) and (2) of this section. 

(1) You must calculate the CO2 mass emissions rate for your affected facility using the 

calculation procedures in paragraphs (g)(1)(i) through (v) of this section with the hourly CO2

mass emissions and gross or net energy output data determined and recorded according to the 

procedures in paragraph (f) of this section for each operating hour in the applicable compliance 

period (i.e., 12-operating months or 84-operating months). 

(i) You must only use operating hours in the compliance period for which you have valid 

data for all the parameters you use to determine the hourly CO2 mass emissions and gross or net

output data. You must not use operating hours which use the substitute data provisions of part 75 

of this chapter for any of the parameters in the calculation. For the compliance determination 

calculation, you must obtain valid hourly values for a minimum of 95 percent of the operating 

hours in the applicable compliance period. 

(ii) You must calculate the total CO2 mass emissions by summing all of the valid hourly 

CO2 mass emissions values for the applicable compliance period. If exhaust gases from the 

affected facility are emitted to the atmosphere through multiple stacks or ducts, you must 

calculate the total CO2 mass emissions for the affected facility by summing the total CO2 mass 

emissions from each of the individual stacks or ducts. 

(iii) For each operating hour of the compliance period used in paragraph (g)(1)(ii) of this 

section to calculate the total CO2 mass emissions, you must determine the affected facility’s 

corresponding hourly gross or net energy output using the appropriate definitions in § 60.42Da 

and paragraph (k) of this section and using the procedure specified in paragraphs (g)(3)(iii)(A) 

through (D) of this section. 

(A) Calculate Pgross/net for your affected facility using the following equation: 

ܲ௚௥௢௦௦/௡௘௧ = ሺܲ݁ሻௌ் ൅	 ሺܲ݁ሻ஼் 	൅	 ሺܲ݁ሻூா െ ሺܲ݁ሻிௐ

T 	൅ 	0.75 ൈ ሾ ሺܲݐሻ௉ௌ 	൅	 ሺܲݐሻுோ 	൅	 ሺܲݐሻூா ሿ

Where: a

Pgross/net = Gross or net energy output of your affected facility in megawatt-hours in 

(MWh). 

(Pe)ST = Electric energy output plus mechanical energy output (if any) of steam 

turbines in MWh. 

(Pe)CT = Electric energy output plus mechanical energy output (if any) of stationary 

combustion turbine(s) in MWh. 

Comment [FC5]: Technical corrections included 

throughout 
Page 7 of 45

(Pe)IE = Electric energy output plus mechanical energy output (if any) of your 

affected facility’s integrated equipment that provides electricity or 

mechanical energy to the affected facility or auxiliary equipment in MWh. 

(Pe)FW = Electric energy used to power boiler feedwater pumps at steam generating 

units in MWh. This term is not applicable to IGCC facilities or facilities 

complying with a net output based standard. 

(Pt)PS = Useful thermal energy output of steam (measured relative to ISO SATP 

conditions, as applicable) that is used for applications that do not generate 

additional electricity, produce mechanical energy output, or enhance the 

performance of the affected facility. This term is calculated using the 

equation specified in paragraph (g)(3)(iii)(B) of this section in MWh. 

(Pt)HR = Hourly useful thermal energy output (measured relative to ISO SATP 

conditions, as applicable) from heat recovery that is used for applications 

other than steam generation or performance enhancement of the affected 

facility in MWh. 

(Pt)IE = Useful thermal energy output (relative to ISO SATP conditions, as 

applicable) from any integrated equipment that provides thermal energy to 

the affected facility or auxiliary equipment in MWh. 

T = Electric Transmission and Distribution Factor. 

T = 0.95 for a combined heat and power affected facility where at least on 

an annual basis 20.0 percent of the total gross or net energy output consists 

of electric or direct mechanical output and 20.0 percent of the total gross 

or net energy output consists of useful thermal energy output on a rolling 3 

year basis. 

T = 1.0 for all other affected facilities. 

(B) If applicable to your affected facility, calculate (Pt)PS using the following equation: 

ሺܲݐሻ௉ௌ 	ൌ	 ܳ௠ 	ൈ 	ܪ

3.6	 ൈ	 10ଽ

Where: 

Qm = Measured steam flow in kilograms (kg) (or pounds (lb)) for the operating 

hour. 

H = Enthalpy of the steam at (measured temperature and pressure relative to 

ISO SATP conditions, as applicable) in Joules per kilogram (J/kg) (or 

Btu/lb). 

3.6 x 109

 = Conversion factor (J/MWh) (or 3.413 x 106 Btu/MWh). 

(C) For an operating hour in which there is no gross or net electric load, but there is 

mechanical or useful thermal output, you must still determine the gross or net energy output for 
Page 8 of 45

that hour. In addition, for an operating hour in which there is no useful output, you must still 

determine the hourly gross CO2 emissions for that hour. For hours or partial hours where there is 

no gross generation, net electric output shall be zero.

(D) If hourly CO2 mass emissions are determined for a common stack, you must 

determine the hourly gross or net energy output (electric, thermal, and/or mechanical, as 

applicable) by summing the hourly loads for the individual affected facility and you must express 

the operating time as “stack operating hours” (as defined in § 72.2 of this chapter). 

(iv) You must calculate the total gross or net energy output by summing the hourly gross 

or net energy output values for the affected facility determined from paragraph (g)(1)(iii) of this 

section for all of the operating hours in the applicable compliance period. 

(v) You must calculate the CO2 mass emissions rate for the applicable compliance period 

interval by dividing the total CO2 mass emissions value from paragraph (g)(1)(ii) of this section 

by the total gross or net energy output value from paragraph (g)(1)(iv) of this section. 

(2) You must determine compliance with the CO2 emissions limitation in paragraph (c) of 

this section is determined as specified in paragraphs (g)(2)(i) and (ii) of this section using the 

CO2 mass emissions rate for your affected facility that you determined in paragraph (g)(1) of this 

section. 

(i) If the CO2 mass emissions rate for your affected facility is less than or equal to the 

CO2 emissions limitation applicable to your affected facility, then your affected facility is in 

compliance with the CO2 emissions limitation. If you attain compliance with the CO2 emissions 

limitation at a common stack for two or more affected facilities subject to the same CO2

emissions limitation, each affected facility sharing the stack is in compliance with the CO2

emissions limitation. 

(ii) If the CO2 mass emissions rate for the affected facility is greater than the CO2

emissions limitation in paragraph (c) of this section applicable to the affected facility, then the 

affected facility has excess CO2 emissions. 

(h) You must prepare and submit notifications and reports according to paragraphs (h)(1) 

through (4) of this section. 

(1) You must prepare and submit the notifications in §§ 60.7(a)(1) and (a)(3) and 60.19, 

as applicable to your affected facility. 

(2) You must prepare and submit notifications in § 75.61 of this chapter, as applicable to 

your affected facility. 

(3) You must submit electronic quarterly reports according to the requirements specified 

in paragraphs (h)(3)(i) through (iii) of this section. 

(i) Initially, after you have accumulated the required number of operating months for the 

CO2 emission limitation compliance period that you have chosen to comply with (i.e., 12-

operating months or 84-operating months), you must submit a report for the calendar quarter that 

includes the final (12th- or 84th) operating month no later than 30 days after the end of that 

quarter. Thereafter, you must submit a report for each subsequent calendar quarter no later than 

30 days after the end of the quarter. 

Comment [FC6]: During periods of 

startup/shutdown where the facility is not generating 

power and “purchasing” power to run the facility net 

electricity is negative. There periods will be counted 

as zero and not negative. 
Page 9 of 45

(ii) In each quarterly report you must include the information in paragraphs (h)(3)(ii)(A) 

through (E) of this section. 

(A) The CO2 emission limitation compliance period with which you have chosen to 

comply. 

(B) Any months in the calendar quarter that you are not counting as operating months. 

(C) For each operating month in the calendar quarter, the corresponding average CO2

mass emissions rate for the applicable compliance period interval that you determined according 

to paragraph (g) of this section. 

(D) The percentage of valid CO2 mass emission rates in each compliance period (i.e., the 

total number of valid CO2 mass emission rates in that period divided by the total number of 

operating hours in that period, multiplied by 100 percent). 

(E) Any operating months in the calendar quarter with excess CO2 emissions. 

(iii) In the final quarterly report of each calendar year you must include the following: 

(A) Net electric output sold to an electric grid over the calendar year; and 

(B) The potential electric output of the facility. 

(iv) You must submit each electronic report using the Emissions Collection and 

Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in 

the EPA Office of Atmospheric Programs. 

(4) You must meet all applicable reporting requirements and submit reports as required 

under subpart G of part 75 of this chapter. 

(5) If your affected unit uses geologic sequestration to meet the applicable emissions 

limit, you must report in accordance with the requirements of 40 CFR part 98, subpart PP and 

either: 

(i) if injection occurs onsite, report in accordance with the requirements of 40 CFR part 

98, subpart RR, or 

(ii) if injection occurs offsite, transfer the captured CO2 to a facility or facilities that 

reports in accordance with the requirements of 40 CFR part 98, subpart RR. 

(i) For each affected electric utility stream generating unit, you must maintain records 

according to paragraphs (i)(1) through (i)(8) of this section. 

(1) You must comply with the applicable recordkeeping requirements and maintain 

records as required under subpart F of part 75 of this chapter. 

(2) You must maintain records of the calculations you performed to determine the total 

CO2 mass emissions for each operating month, and the averages for each compliance period 

interval (i.e., 12-operating months or 84-operating months, as applicable to the CO2 emissions 

limitations). 

(3) You must maintain records of the applicable data recorded and calculations performed 

that you used to determine the gross or net energy output for each operating month. 

(4) You must maintain records of the calculations you performed to determine the 

percentage of valid CO2 mass emission rates in each compliance period. 
Page 10 of 45

(5) You must maintain records of the calculations you performed to assess compliance 

with each applicable CO2 emissions limitation in paragraph (c) of this section. 

(6) Your records must be in a form suitable and readily available for expeditious review. 

(7) You must maintain each record for 5 years after the date of each occurrence, 

measurement, maintenance, corrective action, report, or record except those records required to 

demonstrate compliance with an 84-operating month compliance period. You must maintain 

records required to demonstrate compliance with an 84-operating month compliance period for at 

least 10 years following the date of each occurrence, measurement, maintenance, corrective 

action, report, or record. 

(8) You must maintain each record on site for at least 2 years after the date of each 

occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. 

You may maintain the records off site and electronically for the remaining year(s) as required by 

this subpart. 

(j) PSD and Title V Thresholds for Greenhouse Gases. (1) For purposes of 40 

CFR 51.166(b)(49)(ii), with respect to GHG emissions from new affected facilities, the 

“pollutant that is subject to the standard promulgated under section 111 of the Act” shall 

be considered to be the pollutant that otherwise is subject to regulation under the Act as 

defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted 

to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48). 

(2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from 

new affected facilities, the “pollutant that is subject to the standard promulgated under 

section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to 

regulation under the Act as defined in 40 CFR 52.21(b)(49). 

(3) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from new 

affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of 

the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as 

defined in 40 CFR 70.2. 

(4) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from 

new affected facilities, the “pollutant that is subject to any standard promulgated under 

section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject 

to regulation" as defined in 40 CFR 71.2. 

(k) For purposes of this section, the following definitions apply: 

Gross energy output means: 

(i) Except as provided under paragraph (ii) of this definition, for electric utility steam 

generating units, the gross electric or mechanical output from the affected facility (including, but 

not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) minus 

any electricity used to power the feedwater pumps plus 75 percent of the useful thermal output

measured relative to ISO conditions that is not used to generate additional electric or mechanical 

output or to enhance the performance of the unit (e.g., steam delivered to an industrial process 

for a heating application); 

(ii) For electric utility steam generating unit combined heat and power facilities where at 

least 20.0 percent of the total gross energy output consists of electric or direct mechanical output 

Comment [FC7]: Redundant with definition of 

useful thermal output 
Page 11 of 45

and at least 20.0 percent of the total gross energy output consists of thermal output on a rolling 3 

year basis, the gross electric or mechanical output from the affected facility (including, but not 

limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) minus any 

electricity used to power the feedwater pumps, that difference divided by 0.95, plus 75 percent of 

the useful thermal output measured relative to ISO conditions that is not used to generate 

additional electric or mechanical output or to enhance the performance of the unit (e.g., steam 

delivered to an industrial process for a heating application); 

(iii) Except as provided under paragraph (ivi) of this definition, for a IGCC electric utility 

generating unit, the gross electric or mechanical output from the affected facility (including, but 

not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) plus 75 

percent of the useful thermal output measured relative to ISO conditions that is not used to 

generate additional electric or mechanical output or to enhance the performance of the unit (e.g., 

steam delivered to an industrial process for a heating application); or

(iv) For IGCC electric utility generating unit combined heat and power facilities where at 

least 20.0 percent of the total gross energy output consists of electric or direct mechanical output 

and at least 20.0 percent of the total gross energy output consists of thermal output on a rolling 3 

year basis, the gross electric or mechanical output from the affected facility (including, but not 

limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) divided by 

0.95, plus 75 percent of the useful thermal output measured relative to ISO conditions that is not 

used to generate additional electric or mechanical output or to enhance the performance of the 

unit (e.g., steam delivered to an industrial process for a heating application).;

IGCC facility is an integrated gasification combined cycle electric utility steam 

generating unit, which means an electric utility combined cycle facility that is designed to burn 

fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition 

of natural gas plus any integrated equipment that provides electricity or useful thermal output to 

either the affected facility or auxiliary equipment. The Administrator may waive the 50 percent 

solid-derived fuel requirement during periods of the gasification system construction, startup and 

commissioning, shutdown, or repair. No solid fuel is directly burned in the facility during 

operation. 

Net-electric salesoutput means: 

(i) Except as provided under paragraph (ii) of this definition, the gross electric sales to the 

utility power distribution system minus purchased power on a calendar year basis, or 

(ii) For combined heat and power facilities where at least 20.0 percent of the total gross 

or net energy output consists of electric or direct mechanical output and at least 20.0 percent of 

the total gross or net energy output consists of thermal output, the gross electric sales to the 

utility power distribution system minus purchased power of the thermal host facility or facilities

on a calendar year basis; and. 

(iii) Electricity supplied to other facilities that produce electricity to offset auxiliary loads 

are included when calculating net-electric sales.

Net-electric output means: the amount of gross generation the generator(s) produces 

(including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas 

expander(s)), as measured at the generator terminals, less the electricity used to operate the plant 

(i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control 

Comment [FC8]: Use “net-electric sales” so we 

don’t have to use “for applicability purposes” and 

“for compliance purposes” for net electric output. 

Comment [FC9]: Not necessary since time frame 

specific directly in text. 

Comment [FC10]: Net electric output does not 

account for supplying electric power to other EGUs. 

For example, a simple cycle combustion turbine colocated with a coal-fired EGU would not be able to 

say it was supplying power to coal-fired EGU to 

offset auxiliary power requirements of the coal-fired 

EGU. 
Page 12 of 45

equipment, other electricity needs, and transformer losses as measured at the transmission side of 

the step up transformer (e.g., the point of sale). 

Net energy output means: 

(i) Except as provided under paragraph (ii) of this definition, the net electric or 

mechanical output from the affected facility plus 75 percent of the useful thermal output; or 

(ii) For combined heat and power facilities where at least 20.0 percent of the total gross 

or net energy output consists of electric or direct mechanical output and at least 20.0 percent of 

the total gross or net energy output consists of thermal output on a rolling 3 year basis, the net 

electric or mechanical output from the affected facility divided by 0.95, plus 75 percent of the 

useful thermal output. 

Potential electric output means: 

(i) Either 33 percent or the design net electric output efficiency, at the election of the 

owner/operator of the affected facility, 

(ii) Multiplied by the maximum design heat input capacity of the steam generating unit, 

(iii) Divided by 3,413 Btu/KWh, 

(iv) Divided by 1,000 kWh/MWh, and 

(v) Multiplied by 8,760 h/yr. 

(vi) For example, a 35 percent efficient steam generating unit with a 100 MW (341 

MMBtu/h) fossil-fuel heat input capacity would have a 310,000 MWh 12 month potential 

electric output capacity. 

Standard ambient temperature and pressure (SATP) conditions means 298.15 

Kelvin (25o C, 77 oF)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The 

enthalpy of water at SATP conditions is 45 Btu/lb. 

Steam generating unit means any furnace, boiler, or other device used for 

combusting fuel for the purpose of producing steam (nuclear steam generators are not 

included) plus any integrated equipment that provides electricity or useful thermal output 

to either the boiler or auxiliary equipment. 

Useful thermal output means the thermal energy made available for use in any heating 

application (e.g., steam delivered to an industrial process for a heating application, including 

thermal cooling applications) that is not used for electric generation, mechanical output at the 

affected facility, or to directly enhance the performance of the affected facility (e.g., economizer 

output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered 

useful thermal output). Useful thermal output for affected facilities with no condensate return (or 

other thermal energy input to the affected facility) or where measuring the energy in the 

condensate (or other thermal energy input to the affected facility) would not meaningfully impact 

the emission rate calculation is measured against the energy in the thermal output at SATP 

conditions. Affected facilities with meaningful energy in the condensate return (or other thermal 

energy input to the affected facility) must measure the energy in the condensate and subtract that 

energy relative to SATP conditions from the measured thermal output. 

 

Comment [FC11]: Soliciting comment on 100% 

thermal credit 

Comment [FC12]: Thermal energy used for coal 

drying is considered useful thermal output – could be 

done offsite by a separate thermal source and would 

not be included in the calculation. 

Comment [FC13]: Changing form ISO 

conditions since SATP is closer to makeup water 

conditions (45 Btu/lb instead of 27 Btu/lb). 
Page 13 of 45

Subpart KKKK -— Standards of Performance for Stationary Combustion Turbines 

 3. Section 60.4305 is amended by adding paragraph (c) to read as follows: 

§ 60.4305 Does this subpart apply to my stationary combustion turbine? 

* * * * * 

(c) For purposes of regulation of greenhouse gases, the applicable provisions of this 

subpart affect your stationary combustion turbine if it serves a generator capable of selling greater 

than 25 MW to a utility power distribution system and commenced construction after January 8, 

2014 or it commenced reconstruction or modification after [INSERT DATE OF PUBLICATION 

IN THE FEDERAL REGISTER].

4. Section 60.4315 is revised to read as follows: 

§ 60.4315 What pollutants are regulated by this subpart? 

(a) The pollutants regulated by this subpart are nitrogen oxides (NOX), sulfur dioxide 

(SO2), and greenhouse gases. 

(b)(1) The greenhouse gases regulated by this subpart consist of carbon dioxide (CO2). 

(2) PSD and Title V Thresholds for Greenhouse Gases. (i) For purposes of 40 

CFR 51.166(b)(49)(ii), with respect to GHG emissions from affected stationary 

combustion turbine, the “pollutant that is subject to the standard promulgated under 

section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to 

regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by 

the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 

51.166(b)(48). 

(ii) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from 

affected stationary combustion turbines, the “pollutant that is subject to the standard 

promulgated under section 111 of the Act” shall be considered to be the pollutant that 

otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49). 

(iii) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from 

affected stationary combustion turbines, the “pollutant that is subject to any standard 

promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise 

is "subject to regulation" as defined in 40 CFR 70.2. 

(iv) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected 

stationary combustion turbines, the “pollutant that is subject to any standard promulgated under 

section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to 

regulation" as defined in 40 CFR 71.2. 

5. Section 60.4326 is added to read as follows: 

§ 60.4326 What CO2 emissions standard must I meet? 

You must not discharge from your affected stationary combustion turbine into the 

atmosphere any gases that contain CO2 in excess of the applicable CO2 emissions standard 

specified in Table 2 of this subpart. 

6. Section 60.4333 is amended by adding paragraph (c) to read as follows: 

Comment [FC14]: Added to avoid covering 

large industrial units not connected to a generator 

being subject to “no emision standard” 
Page 14 of 45

§ 60.4333 What are my general requirements for complying with this subpart? 

* * * * * 

(c) If you own or operate an affected stationary combustion turbine subject to a CO2

emissions standard in §60.4326, you must make compliance determinations on a 12-operating 

month rolling average basis, and you must determine compliance monthly by calculating the 

average CO2 emissions rate for the affected stationary combustion turbine at the end of each 12-

operating month period. 

7. Section 60.4373 is added under undesignated center heading “Monitoring” to read as 

follows: 

§ 60.4373 How do I monitor and collect data to demonstrate compliance with my CO2 

emissions standard using a CO2 CEMS? 

(a) You must prepare a monitoring plan in accordance with the applicable provisions in § 

75.53(g) and (h) of this chapter. 

(b) You must measure the hourly CO2 mass emissions from each affected stationary 

combustion turbine using the procedures in paragraphs (b)(1) through (5) of this section, except 

as provided in paragraph (c) of this section. 

(1) You must install, certify, operate, maintain, and calibrate a CO2 continuous emission 

monitoring system (CEMS) to directly measure and record CO2 concentrations in the stationary 

combustion turbine exhaust gases emitted to the atmosphere and an exhaust gas flow rate 

monitoring system according to § 75.10(a)(3)(i) of this chapter. If you measure CO2

concentration on a dry basis, you must also install, certify, operate, maintain, and calibrate a 

continuous moisture monitoring system, according to § 75.11(b) of this chapter. 

(2) For each monitoring system that you use to determine the CO2 mass emissions, you 

must meet the applicable certification and quality assurance procedures in § 75.20 of this chapter 

and Appendices B and D to part 75 of this chapter. 

(3) You must use a laser device to measure the dimensions of each exhaust gas stack or 

duct at the flow monitor and the reference method sampling locations prior to the initial setup 

(characterization) of the flow monitor. For circular stacks, you must make measure of the 

diameter at three or more distinct locations and average the results. For rectangular stacks or 

ducts, you must measure each dimension (i.e., depth and width) at three or more distinct 

locations and average the results. If the flow rate monitor or reference method sampling site is 

relocated, you must repeat these measurements at the new location. 

(4) You must use unadjusted exhaust gas volumetric flow rates only to determine the 

hourly CO2 mass emissions from the affected stationary combustion turbine; you must not apply 

the bias adjustment factors described in section 7.6.5 of Appendix A to part 75 of this chapter to 

the exhaust gas flow rate data. 

(5) If you chose to use Method 2 in Appendix A-1 to this part to perform the required 

relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a 

calibrated Type-S pitot tube or pitot tube assembly. You must not use the default Type-S pitot 

tube coefficient. 

(c) As an alternative to complying with paragraph (b) of this section, you may determine 
Page 15 of 45

the hourly CO2 mass emissions by using Equation G-4 in Appendix G to part 75 of this chapter 

according to the requirements specified in paragraphs (c)(1) and (2) of this section. 

(1) You must implement the applicable procedures in appendix D to part 75 of this 

chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of 

fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel 

combusted. 

(2) You may determine site-specific carbon-based F-factors (Fc) using Equation F-7b in 

section 3.3.6 of Appendix F to part 75 of this chapter, and you may use these Fc values in the 

emissions calculations instead of using the default Fc values in the Equation G-4 nomenclature. 

(d) You must install, calibrate, maintain, and operate a sufficient number of watt meters 

to continuously measure and record the gross electric output from the affected stationary 

combustion turbine. Measurements must be performed using 0.2 class electricity metering 

instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. If the 

affected stationary combustion turbine is a CHP stationary combustion turbine, you must also 

install, calibrate, maintain, and operate meters to continuously determine and record the total 

useful recovered thermal energy. For process steam applications, you will need to install, 

calibrate, maintain, and operate meters to continuously determine and record steam flow rate, 

temperature, and pressure. If the affected stationary combustion turbine has a direct mechanical 

drive application, you must submit a plan to the Administrator or delegated authority for 

approval of how gross energy output will be determined. Your plan shall ensure that you install, 

calibrate, maintain, and operate meters to continuously determine and record each component of 

the determination. 

(e) If two or more affected stationary combustion turbines serve a common electric 

generator, you must apportion the combined hourly gross output to the individual stationary 

combustion turbines using a plan approved by the Administrator (e.g., using steam load or heat 

input to each affected stationary combustion turbine). Your plan shall ensure that you install, 

calibrate, maintain, and operate meters to continuously determine and record each component of 

the determination. 

(f) In accordance with § 60.13(g), if two or more stationary combustion turbines that 

implement the continuous emission monitoring provisions in paragraph (b) of this section share a 

common exhaust gas stack and are subject to the same emissions standard under § 60.4326, you 

may monitor the hourly CO2 mass emissions at the common stack in lieu of monitoring each 

stationary combustion turbine separately. If you choose this option, the hourly gross load 

(electric, thermal, and/or mechanical, as applicable) must be the sum of the hourly loads for the 

individual stationary combustion turbines and you must express the operating time as “stack 

operating hours” (as defined in § 72.2 of this chapter). If you attain compliance with the 

applicable emissions standard in § 60.4326 at the common stack, each stationary combustion 

turbine sharing the stack is in compliance. 

(g) In accordance with § 60.13(g), if the exhaust gases from a stationary combustion 

turbine that implements the continuous emission monitoring provisions in paragraph (b) of this 

section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed 

to a common stack through multiple ducts and you chose to monitor in the ducts), you must 

monitor the hourly CO2 mass emissions and the “stack operating time” (as defined in § 72.2 of 

this chapter) at each stack or duct separately. In this case, you determine compliance with the 
Page 16 of 45

applicable emissions standard in § 60.4326 by summing the CO2 mass emissions measured at the 

individual stacks or ducts and dividing by the total gross output for the unit. 

8. Section 60.4374 is added under undesignated center heading “Monitoring” to read as 

follows: 

§ 60.4374 How do I demonstrate compliance with my CO2 emissions standard and 

determine excess emissions? 

(a) You must calculate the CO2 mass emissions rate for your affected stationary 

combustion turbine by using the hourly CO2 mass emissions and total gross output data 

determined and recorded according to the procedures in § 60.4373 for the compliance period for 

the CO2 emissions standard applicable to the affected stationary combustion turbine, and the 

calculation procedures in paragraphs (a)(1) through (a)(5) of this section. 

(1) You must only use operating hours in the compliance period for the compliance 

determination calculation for which you obtained valid data for all parameters you used to 

determine the hourly CO2 mass emissions and gross output data, are used for the compliance 

determination calculation. You must not include operating hours in which you used the substitute 

data provisions of part 75 of this chapter for any of the parameters in the calculation. For the 

compliance determination calculation, you must obtain valid hourly CO2 mass emission values 

for a minimum of 95 percent of the operating hours in the compliance period. 

(2) You must calculate the total CO2 mass emissions by summing the hourly CO2 mass 

emissions values for the affected stationary combustion turbine determined to be valid according 

to the conditions specified in paragraph (a)(1) of this section for all of the operating hours in the 

applicable compliance period. 

(3) For each operating hour of the compliance period used in paragraph (a)(2) of this 

section to calculate the total CO2 mass emissions, you must determine the affected stationary 

combustion turbine’s corresponding hourly gross output (Pgross) by applying the appropriate 

definitions in §§ 60.4420 and 60.4421 of this subpart and according to the procedures specified 

in paragraphs (a)(3)(i) and (iv) of this section . 

(i) Calculate Pgross for your affected stationary combustion turbine using the 

following equation: 

ܲ௚௥௢௦௦ = ሺܲ݁ሻ஼் ൅ 	 ሺܲ݁ሻௌ் 	൅ 	 ሺܲ݁ሻூா

T 	൅ 	0.75 ൈ ሾ	ሺܲݐሻ௉ௌ 	൅	 ሺܲݐሻுோ 	൅	 ሺܲݐሻூா	ሿ

Where: 

Pgross = Gross energy output of your affected stationary combustion turbine in 

megawatt-hours in (MWh). 

(Pe)CT = Electric energy output plus mechanical energy output (if any) of stationary 

combustion turbines in MWh. 

(Pe)ST = Electric energy output plus mechanical energy output (if any) of steam 

turbines in MWh. 

(Pe)IE = Electric energy output plus mechanical energy output (if any) of your 

affected stationary combustion turbine’s integrated equipment that 

provides electricity to the affected facility or auxiliary equipment in MWh. 
Page 17 of 45

(Pt)PS = Useful thermal energy output of steam (relative to ISOSATP conditions, 

as applicable) that is used for applications that do not generate additional 

electricity, produce mechanical energy output, enhance the performance of 

the affected facility. This is Ccalculated using the equation specified in 

paragraph (a)(3)(ii) of this section in MWh. 

(Pt)HR = Useful thermal energy output (relative to ISO SATP conditions, as 

applicable) from heat recovery that is used for applications other than 

steam generation or performance enhancement of the affected facility in 

MWh. 

(Pt)IE = Useful thermal energy output (relative to ISO SATP conditions, as 

applicable) from any integrated equipment that provides input to the 

affected facility or auxiliary equipment in MWh. 

T = Electric Transmission and Distribution Factor. 

T = 0.95 for a CHP stationary combustion turbine where at least on an 

annual basis 20.0 percent of the total gross energy output consists of 

electric or direct mechanical output and 20.0 percent of the total gross 

energy output consists of useful thermal energy output on a rolling 3 year 

basis. 

T = 1.0 for all other affected stationary combustion turbines. 

(ii) If applicable to your affected stationary combustion turbine, calculate (Pt)PS using the 

following equation: 

ሺܲݐሻ௉ௌ 	ൌ	 ܳ௠ 	ൈ 	ܪ

3.6	 ൈ	 10ଽ

Where: 

Qm = Measured steam flow in kilograms (kg) (or pounds (lb)) for the operating 

hour. 

H = Enthalpy of the steam at measured temperature and pressure (relative to 

ISO SATP conditions, as applicable) in Joules per kilogram (J/kg) (or 

Btu/lb). 

3.6 x 109

 = Conversion factor (J/MWh) (or 3.413 x 106 Btu/MWh). 

(iii) You must determine the hourly gross energy output for each operating hour in which 

there is no electric output, but there is mechanical output or useful thermal output. In addition 

you must determine the hourly gross CO2 emissions for each operating hour in which there is no 

useful output. 

(iv) In the case for which compliance is demonstrated according to § 60.4373(f) for 

affected stationary combustion turbines that vent to a common stack, then you must calculate the 

hourly gross energy output (electric, mechanical, and/or thermal, as applicable) by summing the 

hourly gross energy output you determined for each of your individual affected stationary 
Page 18 of 45

combustion turbines that vent to the common stack; and you must express the operating time as 

“stack operating hours” (as defined in § 72.2 of this chapter). 

(4) You must calculate the total gross output for the affected stationary combustion 

turbine’s compliance period by summing the hourly gross output values for the affected 

stationary combustion turbine determined from paragraph (a)(2) of this section for all of the 

operating hours in the applicable compliance period. 

(5) You must calculate the CO2 mass emissions rate for the affected stationary 

combustion turbine by dividing the total CO2 mass emissions value as calculated according to the 

requirements of paragraph (a)(2) of this section by the total gross output value as calculated 

according to the requirements of paragraph (a)(4) of this section. 

(b) If the CO2 mass emissions rate for the affected stationary combustion turbine 

determined according to the procedures specified in paragraph (a) of this section is less than or 

equal to the CO2 emissions standard in Table 2 of this subpart applicable to the affected 

stationary combustion turbine, then your affected stationary combustion turbine is in compliance 

with the emissions standard. If the average CO2 mass emissions rate is greater than the CO2

emissions standard in Table 2 of this subpart applicable to the affected stationary combustion 

turbine, then your affected stationary combustion turbine has excess CO2 emissions. 

9. Section 60.4375 is amended by revising the section heading to read as follows: 

§ 60.4375 What reports must I submit to comply with my NOx and SO2 emissions limits? 

* * * * * 

10. Section 60.4376 is added to read as follows: 

§ 60.4376 What notifications and reports must I submit to comply with my CO2 emissions 

standard? 

(a)(1) You must prepare and submit the notifications specified in §§ 60.7(a)(1) and (a)(3) 

and 60.19, as applicable to your affected stationary combustion turbine. 

(2) You must prepare and submit notifications specified in § 75.61 of this chapter, as 

applicable to your affected stationary combustion turbine. 

(b) You must prepare and submit reports according to paragraphs (b)(1) through (d) of 

this section, as applicable. 

(1) For stationary combustion turbines that are required, by § 60.4333(c), to conduct 

initial and on-going compliance determinations on a 12-operating month rolling average basis for 

the standard in § 60.4326, you must submit electronic quarterly reports as follows. After you 

have accumulated the first 12-operating months for the affected stationary combustion turbine, 

you must submit a report for the calendar quarter that includes the 12th-operating month no later 

than 30 days after the end of that quarter. Thereafter, you must submit a report for each 

subsequent calendar quarter, no later than 30 days after the end of the quarter. 

(2) In each quarterly report, you must include the following information, as applicable: 

(i) Each rolling average CO2 mass emissions rate for which the last (12th) operating 

month in a 12-operating month compliance period falls within the calendar quarter. You must 

calculate each average CO2 mass emissions rate according to the requirements of § 60.4374. You 
Page 19 of 45

must report the dates (month and year) of the 1st and 12th-operating months in each compliance 

period for which you performed a CO2 mass emissions rate calculation. If there are no 

compliance periods that end in the quarter, you must include a statement to that effect; 

(ii) If one or more compliance periods end in the quarter, you must identify each 

operating month in the calendar quarter with excess CO2 emissions; 

(iii) The percentage of valid CO2 mass emission rates (as defined in § 60.4374) in each 

12-operating month compliance period described in paragraph (b)(2)(i) of this section (i.e., the 

total number of valid CO2 mass emission rates in that period divided by the total number of 

operating hours in that period, multiplied by 100 percent); and 

(iv) The CO2 emissions standard (as identified in Table 2 of this subpart) with which your 

affected stationary combustion turbine is complying. 

(3) The final quarterly report of each calendar year must contain the following: 

(i) Net electric output sold to an electric grid over the 4 quarters of the calendar year; and 

(ii) The potential electric output of the stationary combustion turbine. 

(c) You must submit all electronic reports required under paragraph (b) of this section 

using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by 

the Clean Air Markets Division in the Office of Atmospheric Programs of the EPA. 

(d) You must meet all applicable reporting requirements and submit reports as required 

under subpart G of part 75 of this chapter. 

11. Section 60.4391 is added to read as follows: 

§ 60.4391 What records must I maintain to comply with my CO2 emissions limits? 

 (a) You must maintain records of the information you used to demonstrate compliance 

with this subpart as specified in § 60.7(b) and (f). 

(b) You must follow the applicable recordkeeping requirements and maintain records as 

required under subpart F of part 75 of this chapter. 

(c) You must keep records of the calculations you performed to determine the total CO2

mass emissions for: 

(1) Each operating month (for all affected units); 

(2) Each compliance period, including, as applicable, each 12-operating month 

compliance period. 

(d) You must keep records of the applicable data recorded and calculations performed 

that you used to determine your affected stationary combustion turbine’s gross output for each 

operating month. 

(e) You must keep records of the calculations you performed to determine the percentage 

of valid CO2 mass emission rates in each compliance period. 

(f) You must keep records of the calculations you performed to assess compliance with 

each applicable CO2 mass emissions standard in § 60.4326. 

(g) You must keep records of the calculations you performed to determine any site-
Page 20 of 45

specific carbon-based F-factors you used in the emissions calculations (if applicable). 

(h)(1) Your records must be in a form suitable and readily available for expeditious 

review. 

(2) You must keep each record for 5 years after the date of each occurrence, 

measurement, maintenance, corrective action, report, or record to demonstrate compliance with a 

12-operating month emissions standard. 

(3) You must keep each record on site for at least 2 years after the date of each 

occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. 

You may keep the records off site and electronically for the remaining year(s) as required by this 

subpart. 

12. Section 60.4395 is revised to read as follows: 

§ 60.4395 When must I submit my reports? 

All of your reports required under § 60.7(c) must be postmarked by the 30th day after the 

end of each 6-month period, except as specified in § 60.4376 

13. Section 60.4421 is added to read as follows: 

§ 60.4421 What definitions with respect to CO2 emissions apply to this subpart? 

As used in this subpart: 

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 (heat 

input from duct burners is not included). 

Excess emissions means a specified averaging period over which either: 

(1) The CO2 emissions rate of your affected stationary combustion turbine exceeds the 

applicable emissions standard in Table 2 of this subpart or § 60.4330; or 

(2) The recorded value of a particular monitored parameter is outside the acceptable 

range specified in the parameter monitoring plan for the affected unit. 

Gross energy output means: 

(1) The gross electric or direct mechanical output from both the combustion turbine 

engine and any associated steam turbine(s) or integrated equipment plus any useful thermal 

output measured relative to ISO SATP conditions (except for GHG calculations in § 60.4374 as 

only 75 percent credit is given) that is not used to generate additional electric or mechanical 

output or to enhance the performance of the unit (e.g., steam delivered to an industrial process 

for a heating application). 

(2) For a CHP stationary combustion turbine where at least 20.0 percent of the total gross 

energy output consists of electric or direct mechanical output and at least 20.0 percent of the total 

gross energy output consists of useful thermal output on a rolling 3-year basis, the sum of the 

gross electric 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 SATP conditions (except for GHG calculations in § 60.4374 as only 75 percent credit is 

given) that is not used to generate additional electric or mechanical output or to enhance the 
Page 21 of 45

performance of the unit (e.g., steam delivered to an industrial process for a heating application). 

Net-electric salesoutput means: 

(1) The gross electric sales to the utility power distribution system minus purchased 

power on a 3 calendar year rolling average basis; or 

(2) For combined heat and power facilities where at least 20.0 percent of the total gross 

energy output consists of electric or direct mechanical output and at least 20.0 percent of the total 

gross energy output consists of useful thermal output on a 3 calendar year rolling average basis, 

the gross electric sales to the utility power distribution system minus purchased power of the 

thermal host facility or facilities on a three calendar year rolling average basis;. and 

(3) Electricity supplied to other facilities that produce electricity to offset auxiliary loads 

are included when calculating net-electric sales.

Net-electric output means: the amount of gross generation a generator produces, as 

measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary 

loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, 

other electricity needs, and transformer losses as measured at the transmission side of the step up 

transformer (e.g., the point of sale).

Net energy output means: 

(i) Except as provided under paragraph (ii) of this definition, the net electric or 

mechanical output from both the combustion turbine engine and any associated steam turbine(s) 

or integrated equipment plus 75 percent of the useful thermal output; or 

(ii) For combined heat and power facilities where at least 20.0 percent of the total gross 

energy output consists of electric or direct mechanical output and at least 20.0 percent of the total 

gross energy output consists of thermal output on a rolling 3 year basis, the net electric or 

mechanical output from both the combustion turbine engine and any associated steam turbine(s) 

or integrated equipment divided by 0.95, plus 75 percent of the useful thermal output. 

Operating month means a calendar month during which any fuel is combusted in the 

affected stationary combustion turbine. 

Potential electric output means 33 percent or the design electric output efficiency on a net 

output basis (at the election of the owner/operator of the affected facility) multiplied by the base 

load rating (expressed in MMBtu/h) of the stationary combustion turbine, multiplied by 106

Btu/MMBtu, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 

h/yr (e.g., a 35 percent efficient stationary combustion turbine with a 100 MW (341 MMBtu/h) 

fossil-fuel heat input capacity would have a 310,000 MWh 12-month potential electric output 

capacity). 

Standard ambient temperature and pressure (SATP) conditions means 298.15 

Kelvin (25o C, 77 oF)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The 

enthalpy of water at SATP conditions is 45 Btu/lb. 

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 sub-components plus any 
Page 22 of 45

integrated equipment that provides electricity or useful thermal output to the combustion turbine 

engine, heat recovery system or auxiliary equipment. 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. 

Useful thermal output means the thermal energy made available for use in any heating 

application (e.g., steam delivered to an industrial process for a heating application, including 

thermal cooling applications) that is not used for electric generation, mechanical output at the 

affected facility, or to directly enhance the performance of the affected facility (e.g., economizer 

output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered 

useful thermal output). Useful thermal output for affected facilities with no condensate return (or 

other thermal energy input to the affected facility) or where measuring the energy in the 

condensate (or other thermal energy input to the affected facility) would not meaningfully impact 

the emission rate calculation is measured against the energy in the thermal output at SATP 

conditions. Affected facilities with meaningful energy in the condensate return (or other thermal 

energy input to the affected facility) must measure the energy in the condensate and subtract that 

energy relative to SATP conditions from the measured thermal output. 

 
Page 23 of 45

14. Table 2 to Subpart KKKK of Part 60 is added to read as follows: 

Table 2 to Subpart KKKK of Part 60 – Carbon Dioxide Emission Limits for Stationary 

Combustion Turbines 

Note: all numerical values have a minimum of 2 significant figures 

Affected Stationary Combustion Turbine CO2 Emission Standard 

Stationary combustion turbine that has a design 

heat input to the turbine engine of greater than 

250 MW (850 MMBtu/h), that combusts over 

90% natural gas on a heat input basis on a 3 

year rolling average basis, and that 

supplieswhere net-electric sales consist of

more than one-third of its potential electric 

output and more than 219,000 MWh netelectric output to a utility distribution system 

on a 3 year rolling average basis. 

450 kilograms (kg) of CO2 per megawatt-hour 

(MWh) of gross output (1,000 lb/MWh) on a 

12-operating month rolling average

Stationary combustion turbine that has a design 

heat input to the turbine engine greater than 73 

MW (250 MMBtu/h) and equal to or less than 

250 MW (850 MMBtu/h), that combusts over 

90% natural gas on a heat input basis on a 3 

year rolling average basis, and where netelectric sales consist of that supplies more than 

one-third of its potential electric output and 

more than 219,000 MWh net-electric output to 

a utility distribution system on a 3 year rolling 

average basis.. 

500 kg of CO2 per MWh of gross output (1,100 

lb CO2/MWh) on a 12-operating month rolling 

average

Stationary combustion turbine that either has a 

design heat input to the turbine engine of 73 

MW (250 MMBtu/h) or less, that combusts 

90% or less natural gas on a heat input basis on 

a 3 year rolling average basis, or where netelectric sales consist ofthat supplies one-third 

or less of its potential electric output or 

219,000 MWh or less net-electric output to a 

utility distribution system on a 3 year rolling 

average basis. 

No emission standard 

 
Page 24 of 45

15. Table 3 to Subpart KKKK of Part 60 is added to read as follows: 

Table 3 to Subpart KKKK of Part 60 – Applicability of Subpart A General Provisions to 

Stationary Combustion Turbine CO2 Emissions Standards in Subpart KKKK 

General 

Provisions 

citation 

Subject of citation 

Applies to 

subpart 

KKKK 

Explanation 

§ 60.1 Applicability Yes 

§ 60.2 Definitions Yes 

§ 60.3 Units and Abbreviations Yes 

§ 60.4 Address Yes 

§ 60.5 

Determination of 

construction or 

modification 

Yes 

§ 60.6 Review of plans Yes 

§ 60.7 Notification and 

Recordkeeping Yes 

Only the requirements to 

submit the notification in § 

60.7(a)(1) and (a)(3) 

§ 60.8 Performance tests No 

§ 60.9 Availability of 

Information Yes 

§ 60.10 State authority Yes 

§ 60.11 

Compliance with 

standards and 

maintenance 

requirements 

No 

§ 60.12 Circumvention Yes 

§ 60.13 Monitoring requirements Yes 

§ 60.14 Modification No 

§ 60.15 Reconstruction No 

§ 60.16 Priority list No 

§ 60.17 Incorporations by 

reference Yes 

§ 60.18 General control device 

requirements No 

§ 60.19 General notification and 

reporting requirements Yes 

 
Page 25 of 45

16. Part 60 is amended by adding subpart TTTT to read as follows: 

Subpart TTTT -- Standards of Performance for Greenhouse Gas Emissions for Electric 

Utility Generating Units 

Sec. 

Applicability 

§ 60.5508 What is the purpose of this subpart? 

§ 60.5509 Am I subject to this subpart? 

Emission Standards 

§ 60.5515 What greenhouse gases are regulated by this subpart? 

§ 60.5520 What CO2 emissions standard must I meet? 

General Compliance Requirements 

§ 60.5525 What are my general requirements for complying with this subpart? 

§ 60.5530 Affirmative defense for violation of emission standards during malfunction 

Monitoring and Compliance Determination Procedures 

§ 60.5535 How do I monitor and collect data to demonstrate compliance? 

§ 60.5540 How do I demonstrate compliance with my CO2 emissions standard and 

determine excess emissions? 

Notifications, Reports, and Records 

§ 60.5550 What notifications must I submit and when? 

§ 60.5555 What reports must I submit and when? 

§ 60.5560 What records must I maintain? 

§ 60.5565 In what form and how long must I keep my records? 

Other Requirements and Information 

§ 60.5570 What parts of the General Provisions apply to my affected facility? 

§ 60.5575 Who implements and enforces this subpart? 

§ 60.5580 What definitions apply to this subpart? 

Applicability 

§ 60.5508 What is the purpose of this subpart? 

This subpart establishes emission standards and compliance schedules for the control of 

greenhouse gas (GHG) emissions from a steam generating unit, IGCC, or a stationary 

combustion turbine that commences construction after January 8, 2014 or commences 

Comment [FC15]: Make consistent 
Page 26 of 45

modification or reconstruction after [INSERT DATE OF PUBLICATION IN THE FEDERAL 

REGISTER].

§ 60.5509 Am I subject to this subpart? 

(a) Except as provided for in paragraph (b) of this section, the subpart applies to any 

steam generating unit, IGCC, or stationary combustion turbine that serves a generator capable of 

selling greater than 25 MW to a utility power distribution system and that commences 

construction after January 8, 2014 or commences modification or reconstruction after [INSERT 

DATE OF PUBLICATION IN THE FEDERAL REGISTER].

(b) You are not subject to the requirements of this subpart if your affected facility meets 

any one of the conditions specified in paragraphs (b)(1) through (b)(5) of this section. 

(1) The proposed Wolverine EGU project described in Permit to Install No. 317-07 

issued by the Michigan Department of Environmental Quality, Air Quality Division, effective 

June 29, 2011 (as revised July 12, 2011). 

(2) The proposed Washington County EGU project described in Air Quality Permit No. 

4911-303-0051-P-01-0 issued by the Georgia Department of Natural Resources, Environmental 

Protection Division, Air Protection Branch, effective April 8, 2010, provided that construction 

had not commenced for NSPS purposes as of January 8, 2014. 

(3) The proposed Holcomb EGU project described in Air Emission Source Construction 

Permit 0550023 issued by the Kansas Department of Health and Environment, Division of 

Environment, effective December 16, 2010, provided that construction had not commenced for 

NSPS purposes as of January 8, 2014. 

(4) Your affected facility is a municipal waste combustor unit that is subject to subpart 

Eb of this part. 

(5) Your affected facility is a commercial or industrial solid waste incineration unit that is 

subject to subpart CCCC of this part. 

Emission Standards 

§ 60.5515 What greenhouse gases are regulated by this subpart? 

(a) The greenhouse gas regulated by this subpart is carbon dioxide (CO2). 

(b) PSD and Title V Thresholds for Greenhouse Gases. (1) For purposes of 40 

CFR 51.166(b)(49)(ii), with respect to GHG emissions from affected facilities, the 

“pollutant that is subject to the standard promulgated under section 111 of the Act” shall 

be considered to be the pollutant that otherwise is subject to regulation under the Act as 

defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted 

to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48). 

(2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from 

affected facilities, the “pollutant that is subject to the standard promulgated under section 

111 of the Act” shall be considered to be the pollutant that otherwise is subject to 

regulation under the Act as defined in 40 CFR 52.21(b)(49). 

(3) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from affected 

facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” 

Comment [FC16]: Add to avoid covering large 

industrial units that to not generate sufficient 

electricity to be subject to the 219,000 MWh 

requirement. 
Page 27 of 45

shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 

CFR 70.2. 

(4) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected 

facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” 

shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 

CFR 71.2. 

§ 60.5520 What CO2 emissions standard must I meet? 

(a) For each affected facility subject to this subpart, you must not discharge from the 

affected facility stack into the atmosphere any gases that contain CO2 in excess of the applicable 

CO2 emissions standard specified in Table 1 or Table 2 to this subpart, as applicable (e.g., the 

emission standards in Table 2 are not applicable to steam generating units and IGCC facilities 

subject to an approved CAA section 111(d) plan), of this subpart, except for owners and 

operators of modified affected facilities complying with the standards specified in paragraph (b) 

of this section, as applicable to the affected facility. 

(b) The owner or operator of a modified steam generating unit or IGCC facility 

complying with the requirements of this paragraph are not required to comply with the emission 

limit in Table 2 to this subpart. 

(1) If the affected facility is not subject to an approved CAA section 111(d) plan (state or 

federal), the owner/operator may elect to comply with a site-specific 12-operating month rolling 

average CO2 emission limit calculated as 2 percent lower than (i.e., 98 percent) the best 

demonstrated annual historical operating performance for the affected facility using historical 

CO2 emissions data for the calendar years 2002 through the most recent full calendar year the 

affected facility was operating prior to the modification using either recorded net output emission 

rate data or gross electrical output and CO2 emissions data as reported under part 75 of this 

chapter. If incomplete or no data has been submitted under part 75 of this chapter, the 

Administrator or delgated authority shall approve the use of alternate data sources. The 

equivalent net output-based standard shall be calculated from gross output-based data assuming a 

7.5 percent auxiliary (i.e., parasitic) load (i.e., the best annual value is divided by 0.925); or 

(2) If the affected facility is subject to an approved CAA section 111(d) plan (state or 

federal), a site-specific 12-operating month rolling average CO2 emission limit determined by the 

CAA section 111(d) implementing authority based on the affected facility performing an energy 

assessment by an energy professional or engineer that have expertise in evaluating energy 

systems to identify applicable energy efficiency projects that you will implement at the affected 

facility to improve the affected facility’s operating performance. You must maintain a copy of 

the most recent energy assessment report. The energy assessment must include at a minimum the 

elements in paragraphs (b)(2)(i) through (b)(2)(iii) of this section. 

(i) A visual inspection of the facility to identify steam leaks or other sources of reduced 

efficiency, 

(ii) A review of available engineering plans and facility operation and maintenance 

procedures and logs, and 

(iii) A comprehensive report detailing the ways to improve efficiency, the cost of specific 

improvements, benefits, and the time frame for recouping those investments. 
Page 28 of 45

General Compliance Requirements 

§ 60.5525 What are my general requirements for complying with this subpart?

(a) You must be in compliance with the emission standards in this subpart that apply to 

your affected facility at all times. However, you must make a compliance determination only at 

the end of the applicable operating month, as provided in paragraphs (a)(1) and (2) of this 

section. 

(1) For each affected facility subject to a CO2 emissions standard based on a 12-operating 

month rolling average, you must determine compliance monthly by calculating the average CO2

emissions rate for the affected facility at the end of each 12-operating month period. 

(2) For each affected facility subject to a CO2 emissions standard based on an 84-

operating month rolling average, you must determine compliance monthly by calculating the 

average CO2 emissions rate for the affected facility at the end of each 84-operating month period. 

(b) At all times you must operate and maintain each affected facility, including associated 

equipment and monitoring equipment, in a manner consistent with safety and good air pollution 

control practice. The Administrator will determine if you are using consistent operation and 

maintenance procedures based on information available to the Administrator that may include, 

but is not limited to, fuel use records, monitoring results, review of operation and maintenance 

procedures and records, review of reports required by this subpart, and inspection of the facility. 

(c) You must conduct an initial compliance determination for your affected facility for 

the applicable emissions standard in § 60.5520, according to the requirements in this subpart, 

within 30 days after the end of the initial compliance period for the CO2 emissions standards 

applicable to your affected facility (i.e., 12-operating months or 84-operating months). The first 

operating month included in this compliance period is the month in which emissions reporting is 

required to begin under §75.64(a) of this chapter.

§ 60.5530 Affirmative defense for violation of emission standards during malfunction. 

In response to an action to enforce the standards set forth in § 60.5520, 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 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) Assertion of affirmative defense. 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 or better 

operation and maintenance practices; 

(iii) Did not stem from any activity or event that could have been foreseen and avoided, 

or planned for; 
Page 29 of 45

(iv) Was not part of a recurring pattern indicative of inadequate design, operation, or 

maintenance; 

(2) Repairs were made as expeditiously as possible when the violation occurred; 

(3) The frequency, amount and duration of the violation (including any bypass) were 

minimized to the maximum extent practicable; 

(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; 

(5) All possible steps were taken to minimize the impact of the violation on ambient air 

quality, the environment, and human health; 

(6) All emissions monitoring and control systems were kept in operation if at all 

possible, consistent with safety and good air pollution control practices; 

(7) All of the actions in response to the violation were documented by properly signed, 

contemporaneous operating logs; 

(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 shall 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 to demonstrate, with all necessary supporting documentation, 

that it has met the requirements set forth in paragraph (a) of this section. This affirmative defense 

report is due after the initial occurrence of the exceedance of the standard in § 60.5520, and on 

the same quarterly reporting schedule as in § 60.5555 (which may be the end of any applicable 

averaging period). If such quarterly report is due less than 45 days after the initial occurrence of 

the violation, the affirmative defense report may be included in the following quarterly report 

required in § 60.5555(a). 

Monitoring and Compliance Determination Procedures 

§ 60.5535 How do I monitor and collect data to demonstrate compliance? 

(a) You must prepare a monitoring plan in accordance with the applicable provisions in § 

75.53(g) and (h) of this chapter. 

(b) You must measure the hourly CO2 mass emissions from each affected facility using 

the procedures in paragraphs (b)(1) through (5) of this section, except as provided in paragraph 

(c) of this section. 

(1) You must install, certify, operate, maintain, and calibrate a CO2 continuous emission 

monitoring system (CEMS) to directly measure and record CO2 concentrations in the affected 

facility exhaust gases emitted to the atmosphere and an exhaust gas flow rate monitoring system 

according to § 75.10(a)(3)(i) of this chapter. If you measure CO2 concentration on a dry basis, 

you must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring 

system, according to § 75.11(b) of this chapter. 
Page 30 of 45

(2) For each monitoring system you use to determine the CO2 mass emissions, you must 

meet the applicable certification and quality assurance procedures in § 75.20 of this chapter and 

Appendices B and D to part 75 of this chapter. 

(3) You must use a laser device to measure the dimensions of each exhaust gas stack or 

duct at the flow monitor and the reference method sampling locations prior to the initial setup 

(characterization) of the flow monitor. For circular stacks, you must measure the diameter at 

three or more distinct locations and average the results. For rectangular stacks or ducts, you must 

measure each dimension (i.e., depth and width) at three or more distinct locations and average 

the results. If the flow rate monitor or reference method sampling site is relocated, you must 

repeat these measurements at the new location. 

(4) You must use only unadjusted exhaust gas volumetric flow rates to determine the 

hourly CO2 mass emissions from the affected facility; you must not apply the bias adjustment 

factors described in section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow 

rate data. 

(5) If you choose to use Method 2 in Appendix A-1 to this part to perform the required 

relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a 

calibrated Type-S pitot tube or pitot tube assembly. You must not use the default Type-S pitot 

tube coefficient. 

(c) If your affected facility exclusively combusts liquid fuel and/or gaseous fuel as an 

alternative to complying with paragraph (b) of this section, you may determine the hourly CO2

mass emissions by using Equation G-4 in Appendix G to part 75 of this chapter according to the 

requirements in paragraphs (c)(1) and (2) of this section. 

(1) You must implement the applicable procedures in appendix D to part 75 of this 

chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of 

fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel 

combusted. 

(2) You may determine site-specific carbon-based F-factors (Fc) using Equation F-7b in 

section 3.3.6 of appendix F to part 75 of this chapter, and you may use these Fc values in the 

emissions calculations instead of using the default Fc values in the Equation G-4 nomenclature. 

(d) You must install, calibrate, maintain, and operate a sufficient number of watt meters 

to continuously measure and record the gross or net electric output from the affected facility. 

Measurements must be performed using 0.2 class electricity metering instrumentation and 

calibration procedures as specified under ANSI Standards No. C12.20. If the affected facility is a 

CHP facility, you must also install, calibrate, maintain, and operate meters to continuously 

determine and record the total useful recovered thermal energy. For process steam applications, 

you will need to install, calibrate, maintain, and operate meters to continuously determine and 

record steam flow rate, temperature, and pressure. If the affected facility has a direct mechanical 

drive application, you must submit a plan to the Administrator or delegated authority for 

approval of how gross or net energy output will be determined. Your plan shall ensure that you 

install, calibrate, maintain, and operate meters to continuously determine and record each 

component of the determination. 

(e) If two or more affected facilities serve a common electric generator, you must 

apportion the combined hourly gross or net output to the individual affected facilities using a 
Page 31 of 45

plan approved by the Administrator (e.g., using steam load or heat input to each affected EGU). 

Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously 

determine and record each component of the determination. 

(f) In accordance with § 60.13(g), if two or more affected facilities that implement the 

continuous emission monitoring provisions in paragraph (b) of this section share a common 

exhaust gas stack and are subject to the same emissions standard under § 60.5520, you may 

monitor the hourly CO2 mass emissions at the common stack in lieu of monitoring each EGU 

separately. If you choose this option, the hourly gross or net load (electric, thermal, and/or 

mechanical, as applicable) must be the sum of the hourly loads for the individual affected facility 

and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this 

chapter). If you attain compliance with the applicable emissions standard in § 60.5520 at the 

common stack, each affected facility sharing the stack is in compliance. 

(g) In accordance with § 60.13(g), if the exhaust gases from an affected facility that 

implements the continuous emission monitoring provisions in paragraph (b) of this section are 

emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a 

common stack through multiple ducts and you elect to monitor in the ducts), you must monitor 

the hourly CO2 mass emissions and the “stack operating time” (as defined in § 72.2 of this 

chapter) at each stack or duct separately. In this case, you must determine compliance with the 

applicable emissions standard in § 60.5520 by summing the CO2 mass emissions measured at the 

individual stacks or ducts and dividing by the total gross or net output for the affected facility. 

§60.5540 How do I demonstrate compliance with my CO2 emissions standard and 

determine excess emissions? 

(a) You must calculate the CO2 mass emissions rate for your affected facility by using the 

hourly CO2 mass emissions and total gross or net output data determined and recorded according 

to the procedures in § 60.5535 for each operating hour in the compliance period for the CO2

emissions standard applicable to the affected facility (i.e., 12- or 84-operating month rolling 

average period), and the calculation procedures in paragraphs (a)(1) through (a)(5) of this 

section. 

(1) You can only use operating hours in the compliance period for the compliance 

determination calculation if valid data are obtained for all parameters you used to determine the 

hourly CO2 mass emissions and the gross or net output data are used for the compliance 

determination calculation. You must not include operating hours in which you used the substitute 

data provisions of part 75 of this chapter for any of those parameters in the calculation. For the 

compliance determination calculation, you must obtain valid hourly CO2 mass emission values 

for a minimum of 95 percent of the operating hours in the compliance period for the CO2 

emissions standard applicable to the affected facility. 

(2) You must calculate the total CO2 mass emissions by summing the valid hourly CO2

mass emissions values for all of the operating hours in the applicable compliance period. 

(3) For each operating hour of the compliance period that you used in paragraph (a)(2) of 

this section to calculate the total CO2 mass emissions, you must determine the affected facility’s 

corresponding hourly gross or net output according to the procedures in paragraphs (a)(3)(i) and 

(ii) of this section, as appropriate for the type of affected facility. For an operating hour in which 

there is no gross or net electric load, but there is mechanical or useful thermal output, you must 
Page 32 of 45

still determine the gross or net output for that hour. In addition, for operating hours in which 

there is no useful output, you still need to determine the CO2 emissions for that hour. For hours 

or partial hours where there is no gross generation, net electric output shall be zero.

(i) Calculate Pgross/net for your affected facility using the following equation: 

ܲ௚௥௢௦௦/௡௘௧ = ሺܲ݁ሻௌ் ൅	 ሺܲ݁ሻ஼் 	൅	 ሺܲ݁ሻூா െ ሺܲ݁ሻிௐ

T 	൅ 	0.75 ൈ ሾ ሺܲݐሻ௉ௌ 	൅	 ሺܲݐሻுோ 	൅	 ሺܲݐሻூா ሿ

Where: a 

Pgross/net = Gross or net energy output of your affected facility in megawatt-hours in 

(MWh). 

(Pe)ST = Electric energy output plus mechanical energy output (if any) of steam 

turbines in MWh. 

(Pe)CT = Electric energy output plus mechanical energy output (if any) of stationary 

combustion turbine(s) in MWh. 

(Pe)IE = Electric energy output plus mechanical energy output (if any) of your 

affected facility’s integrated equipment that provides electricity or 

mechanical energy to the affected facility or auxiliary equipment in MWh. 

(Pe)FW = Electric energy used to power boiler feedwater pumps at steam generating 

units in MWh. Not applicable to stationary combustion turbines, or IGCC 

facilities, or facilities complying with a net output based standard. 

(Pt)PS = Useful thermal energy output of steam (measured relative to ISO SATP 

conditions, as applicable) that is used for applications that do not generate 

additional electricity, produce mechanical energy output, or enhance the 

performance of the affected facility. This is Ccalculated using the equation 

specified in paragraph (g)(3)(iii)(B) of this section in MWh. 

(Pt)HR = Hourly useful thermal energy output (measured relative to ISO SATP 

conditions, as applicable) from heat recovery that is used for applications 

other than steam generation or performance enhancement of the affected 

facility in MWh. 

(Pt)IE = Useful thermal energy output (relative to ISO SATP conditions, as 

applicable) from any integrated equipment that provides thermal energy to 

the affected facility or auxiliary equipment in MWh. 

T = Electric Transmission and Distribution Factor. 

T = 0.95 for a combined heat and power affected facility where at least on 

an annual basis 20.0 percent of the total gross or net energy output consists 

of electric or direct mechanical output and 20.0 percent of the total gross 

or net energy output consists of useful thermal energy output on a rolling 3 

year basis. 

T = 1.0 for all other affected facilities. 
Page 33 of 45

(ii) If applicable to your affected facility, you must calculate (Pt)PS using the following 

equation: 

ሺܲݐሻ௉ௌ 	ൌ	 ܳ௠ 	ൈ 	ܪ

3.6	 ൈ	 10ଽ

Where: 

Qm = Measured steam flow in kilograms (kg) (or pounds (lb)) for the operating 

hour. 

H = Enthalpy of the steam at measured temperature and pressure (relative to 

ISO SATP conditions, as applicable) in Joules per kilogram (J/kg) (or 

Btu/lb). 

3.6 x 109

 = Conversion factor (J/MWh) (or 3.413 x 106 Btu/MWh). 

(4) You must calculate the total gross or net output for the affected facility’s compliance 

period by summing the hourly gross or net output values for the affected facility that you 

determined from paragraph (a)(2) of this section for all of the operating hours in the applicable 

compliance period. 

(5) You must calculate the CO2 mass emissions rate for the affected facility by dividing 

the total CO2 mass emissions value calculated according to the procedures in paragraph (a)(2) of 

this section by the total gross or net output value calculated according to the procedures in 

paragraph (a)(4) of this section. 

(b) If the CO2 mass emissions rate for your affected facility that you determined 

according to the procedures specified in paragraph (a) of this section is less than or equal to the 

CO2 emissions standard in Table 1 of this subpart applicable to the affected facility, then your 

affected facility is in compliance with the emissions standard. If the average CO2 mass emissions 

rate is greater than the CO2 emissions standard in Table 1 of this subpart applicable to the 

affected facility, then your affected facility has excess CO2 emissions. 

Notification, Reports, and Records 

§ 60.5550 What notifications must I submit and when? 

(a) You must prepare and submit the notifications specified in §§ 60.7(a)(1) and (a)(3) 

and 60.19, as applicable to your affected facility. 

(b) You must prepare and submit notifications specified in § 75.61 of this chapter, as 

applicable to your affected facility. 

§ 60.5555 What reports must I submit and when? 

(a) You must prepare and submit reports according to paragraphs (a) through (d) of this 

section, as applicable. 

(1) For affected facilities that are required by § 60.5525 to conduct initial and on-going 

compliance determinations on a 12- or 84-operating month rolling average basis for the standard 

in § 60.5520 you must submit electronic quarterly reports as follows. After you have 

accumulated the first 12-operating months for the affected facility (or, the first 84-operating 
Page 34 of 45

months for an affected facility electing to comply with the 84-operating month standard), you 

must submit a report for the calendar quarter that includes the twelfth (or eighty-fourth) 

operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a 

report for each subsequent calendar quarter, no later than 30 days after the end of the quarter. 

(2) In each quarterly report you must include the following information, as applicable: 

(i) Each rolling average CO2 mass emissions rate for which the last (12th or eightyfourth) operating month in a 12- or 84-operating month compliance period falls within the 

calendar quarter. You must calculate each average CO2 mass emissions rate according to the 

procedures in § 60.5540. You must report the dates (month and year) of the first and twelfth (or 

eighty-fourth) operating months in each compliance period for which you performed a CO2 mass 

emissions rate calculation. If there are no compliance periods that end in the quarter, you must 

include a statement to that effect; 

(ii) If one or more compliance periods end in the quarter you must identify each operating 

month in the calendar quarter with excess CO2 emissions; 

(iii) The percentage of valid CO2 mass emission rates (as defined in § 60.5540) in each 

12- or 84-operating month compliance period described in paragraph (a)(1)(i) of this section (i.e., 

the total number of valid CO2 mass emission rates in that period divided by the total number of 

operating hours in that period, multiplied by 100 percent); and 

(iv) The CO2 emissions standard (as identified in Table 1 of this subpart) with which your 

affected facility is complying. 

(3) In the final quarterly report of each calendar year, you must include the following: 

(i) Gross electric output sold to an electric grid over the 4 quarters of the calendar year; 

and 

(ii) The potential electric output of the facility. 

(b) You must submit all electronic reports required under paragraph (a) of this section 

using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by 

the Clean Air Markets Division in the Office of Atmospheric Programs of EPA. 

(c) You must meet all applicable reporting requirements and submit reports as required 

under subpart G of part 75 of this chapter. 

(d) If your affected unit employs geologic sequestration to meet the applicable emission 

limit, you must report in accordance with the requirements of 40 CFR part 98, subpart PP and 

either: 

(1) if injection occurs onsite, report in accordance with the requirements of 40 CFR part 

98, subpart RR, or 

(2) if injection occurs offsite, transfer the captured CO2 to a facility or facilities that 

reports in accordance with the requirements of 40 CFR part 98, subpart RR. 

§ 60.5560 What records must I maintain? 

(a) You must maintain records of the information you used to demonstrate compliance 

with this subpart as specified in § 60.7(b) and (f). 
Page 35 of 45

(b) You must follow the applicable recordkeeping requirements and maintain records as 

required under subpart F of part 75 of this chapter. 

(c) You must keep records of the calculations you performed to determine the total CO2

mass emissions for: 

(1) Each operating month (for all affected units); 

(2) Each compliance period, including, as applicable, each 12-operating month 

compliance period and the 84-operating month compliance period. 

(d) You must keep records of the applicable data recorded and calculations performed 

that you used to determine your affected facility’s gross or net output for each operating month. 

(e) You must keep records of the calculations you performed to determine the percentage 

of valid CO2 mass emission rates in each compliance period. 

(f) You must keep records of the calculations you performed to assess compliance with 

each applicable CO2 mass emissions standard in § 60.5520. 

(g) You must keep records of the calculations you performed to determine any sitespecific carbon-based F-factors you used in the emissions calculations (if applicable). 

§ 60.5565 In what form and how long must I keep my records? 

(a) Your records must be in a form suitable and readily available for expeditious review. 

(b) You must maintain each record for 5 years after the date of each occurrence, 

measurement, maintenance, corrective action, report, or record except those records required to 

demonstrate compliance with an 84-operating month compliance period. You must maintain 

records required to demonstrate compliance with an 84-operating month compliance period for at 

least 10 years following the date of each occurrence, measurement, maintenance, corrective 

action, report, or record. 

(c) You must maintain each record on site for at least 2 years after the date of each 

occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. 

You may maintain the records off site and electronically for the remaining year(s) as required by 

this subpart. 

Other Requirements and Information 

§ 60.5570 What parts of the General Provisions apply to my affected facility? 

Notwithstanding any other provision of this chapter, certain parts of the General 

Provisions in §§ 60.1 through 60.19, listed in Table 2 of this subpart, do not apply to your 

affected facility. 

§ 60.5575 Who implements and enforces this subpart? 

(a) This subpart can be implemented and enforced by the EPA, or a delegated authority 

such as your state, local, or tribal agency. If the Administrator has delegated authority to your 

state, local, or tribal agency, then that agency (as well as the EPA) has the authority to implement 

and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart 

is delegated to your state, local, or tribal agency. 

(b) In delegating implementation and enforcement authority of this subpart to a state, 
Page 36 of 45

local, or tribal agency, the Administrator retains the authorities listed in paragraphs (b)(1) 

through (5) of this section and does not transfer them to the state, local, or tribal agency. In 

addition, the EPA retains oversight of this subpart and can take enforcement actions, as 

appropriate. 

(1) Approval of alternatives to the emission standards. 

(2) Approval of major alternatives to test methods. 

(3) Approval of major alternatives to monitoring. 

(4) Approval of major alternatives to recordkeeping and reporting. 

(5) Performance test and data reduction waivers under § 60.8(b). 

§ 60.5580 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 the maximum amount of heat input (fuel) that a steam generating 

unit can combust on a steady state basis, as determined by the physical design and characteristics 

of the steam generating unit at ISO conditions. For a stationary combustion turbine, base load

rating means 100 percent of the design heat input capacity of the simple cycle portion of the 

stationary combustion turbine at ISO conditions (heat input from duct burners is not included). 

Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite 

by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, 

see § 60.17), coal refuse, and petroleum coke. Synthetic fuels derived from coal for the purpose 

of creating useful heat, including but not limited to solvent-refined coal, gasified coal (not 

meeting the definition of natural gas), coal-oil mixtures, and coal-water mixtures are included in 

this definition for the purposes of this subpart. 

Coal refuse means waste products of coal mining, physical coal cleaning, and coal 

preparation operations (e.g. culm, gob, etc.) containing coal, matrix material, clay, and other 

organic and inorganic material. 

Combined cycle facility means an electric generating unit that uses a stationary 

combustion turbine from which the heat from the turbine exhaust gases is recovered by a heat 

recovery steam generating unit to generate additional electricity.

Combined heat and power facility or CHP facility, (also known as “cogeneration”) means 

an electric generating unit that that use a steam-generating unit or stationary combustion turbine 

to simultaneously produce both electric (or mechanical) and useful thermal energy from the same 

primary energy source. 

Distillate oil means fuel oils that contain no more than 0.05 weight percent nitrogen and 

comply with the specifications for fuel oil numbers 1 and 2, as defined by the American Society 

of Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17); diesel fuel oil 
Page 37 of 45

numbers 1 and 2, as defined by the American Society for Testing and Materials in ASTM D975 

(incorporated by reference, see § 60.17); kerosene, 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). 

Excess emissions means a specified averaging period over which the CO2 emissions rate 

is higher than the applicable emissions standard located in Table 1 of this subpart. 

Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous 

fuel derived from such material for the purpose of creating useful heat. 

Gaseous fuel means any fuel that is present as a gas at ISO conditions and includes, but is 

not limited to, natural gas, refinery fuel gas, process gas, coke-oven gas, synthetic gas, and 

gasified coal. 

Gross energy output means: 

(1) For stationary combustion turbines and IGCC facilities, the gross electric or direct 

mechanical output from both the unit (including, but not limited to, output from steam turbine(s), 

combustion turbine(s), and gas expander(s)) plus 75 percent of the useful thermal output

measured relative to ISO conditions that is not used to generate additional electric or mechanical 

output or to enhance the performance of the unit (e.g., steam delivered to an industrial process 

for a heating application). 

(2) For electric utility steam generating units, the gross electric or mechanical output 

from the affected facility (including, but not limited to, output from steam turbine(s), combustion 

turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps plus 75 

percent of the useful thermal output measured relative to ISO conditions that is not used to 

generate additional electric or mechanical output or to enhance the performance of the unit (e.g., 

steam delivered to an industrial process for a heating application); 

(3) For combined heat and power facilities where at least 20.0 percent of the total gross 

energy output consists of electric or direct mechanical output and 20.0 percent of the total gross 

energy output consists of thermal output on a rolling 3 year basis, the gross electric or 

mechanical output from the affected facility (including, but not limited to, output from steam 

turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the 

feedwater pumps (the electric auxiliary load of boiler feedwater pumps is not applicable to IGCC 

facilities), that difference divided by 0.95, plus 75 percent of the useful thermal output measured 

relative to ISO conditions that is not used to generate additional electric or mechanical output or 

to enhance the performance of the unit (e.g., steam delivered to an industrial process for a 

heating application). 

Heat recovery steam generating unit (HRSG) means a unit in which 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 facility or IGCC facility means a combined cycle 

facility that has a design heat input greater than 73 MW (250MMBtu/h) heat input of fossil fuel 
Page 38 of 45

(either alone or in combination with any other fuel), supplies where net-electric sales consists of 

one-third or more of its potential electric output and more than 219,000 MWh net-electric output 

to a utility distribution system on an annual basis, and is designed to burn fuels containing 50 

percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas plus 

any integrated equipment that provides electricity or useful thermal output to either the affected 

facility or auxiliary equipment. The Administrator may waive the 50 percent solid-derived fuel 

requirement during periods of the gasification system construction, startup and commissioning, 

shutdown, or repair. No solid fuel is directly burned in the unit during operation. 

ISO conditions means 288 Kelvin (15o C), 60 percent relative humidity and 101.3 

kilopascals pressure. 

Liquid fuel means any fuel that is present as a liquid at ISO conditions and includes, but 

is not limited to, distillate oil and residual oil. 

Mechanical output means the useful mechanical energy that is not used to operate the 

affected facility, generate electricity and/or thermal energy, or to enhance the performance of the 

affected facility. Mechanical energy measured in horsepower hour should be converted into 

MWh by multiplying it by 745.7 then dividing by 1,000,000. 

Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), 

composed of at least 70 percent methane by volume or that has a gross calorific value between 

35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard 

cubic foot), that maintains a gaseous state under ISO conditions. In addition, natural gas contains 

20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, natural gas does not 

include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast 

furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a 

process which might result in highly variable sulfur content or heating value. 

Net-electric output sales means: 

(1) The gross electric sales to the utility power distribution system minus purchased 

power on a three calendar year rolling average basis; or 

(2) For combined heat and power facilities where at least 20.0 percent of the total gross 

energy output consists of electric or direct mechanical output and at least 20.0 percent of the total 

gross energy output consists of useful thermal output on a 3 calendar year rolling average basis, 

the gross electric sales to the utility power distribution system minus purchased power of the 

thermal host facility or facilities on a three calendar year rolling average basis; and. 

(3) Electricity supplied to other facilities that produce electricity to offset auxiliary loads 

are included when calculating net-electric sales.

Net-electric output means: the amount of gross generation the generator(s) produces 

(including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas 

expander(s)), as measured at the generator terminals, less the electricity used to operate the plant 

(i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control 

equipment, other electricity needs, and transformer losses as measured at the transmission side of 

the step up transformer (e.g., the point of sale). 

Net energy output means: 
Page 39 of 45

(i) Except as provided under paragraph (ii) of this definition, the net electric or 

mechanical output from the affected facility plus 75 percent of the useful thermal output; or 

(ii) For combined heat and power facilities where at least 20.0 percent of the total gross 

or net energy output consists of electric or direct mechanical output and at least 20.0 percent of 

the total gross or net energy output consists of thermal output on a rolling 3 year basis, the net 

electric or mechanical output from the affected facility divided by 0.95, plus 75 percent of the 

useful thermal output; 

Oil means crude oil or petroleum or a fuel derived from crude oil or petroleum, including 

distillate and residual oil, and gases derived from solid oil-derived fuels (not meeting the 

definition of natural gas). 

Operating month means a calendar month during which any fuel is combusted in the 

affected facility at any time. 

Potential electric output means 33 percent or the design electric output efficiency on a net 

output basis multiplied by the maximum design heat input capacity (expressed in MMBtu/h) of 

the steam generating unit, multiplied by 106

 Btu/MMBtu, divided by 3,413 Btu/KWh, divided by 

1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 percent efficient affected facility with 

a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 310,000 MWh 12 month 

potential electric output capacity). 

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. 

Standard ambient temperature and pressure (SATP) conditions means 298.15 

Kelvin (25o C, 77 oF)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The 

enthalpy of water at SATP conditions is 45 Btu/lb. 

Stationary combustion turbine means all equipment, including but not limited to the 

turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems (except 

emissions control equipment), heat recovery system, fuel compressor, heater, and/or pump, postcombustion emission control technology, and any ancillary components and sub-components 

comprising any simple cycle stationary combustion turbine, any combined cycle combustion 

turbine, and any combined heat and power combustion turbine based system plus any integrated 

equipment that provides electricity or useful thermal output to the combustion turbine engine, 

heat recovery system or auxiliary equipment. 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. If a stationary combustion turbine burns any solid fuel 

directly it is considered a steam generating unit. 

Steam generating unit means any furnace, boiler, or other device used for combusting 

fuel and producing steam (nuclear steam generators are not included) that has a design heat input 

greater than 73 MW (250MMBtu/h) heat input of fossil fuel (either alone or in combination with 

any other fuel) and that supplieswhere net-electric sales consist of one-third or more of its 

potential electric output and more than 219,000 MWh net-electric output to a utility distribution 

system on an annual basis plus any integrated equipment that provides electricity or useful 

thermal output to the affected facility or auxiliary equipment. 
Page 40 of 45

Useful thermal output means the thermal energy made available for use in any industrial 

or commercial process, or used in any heating or cooling application, (e.g., steam delivered to an 

industrial process for a heating application, including thermal cooling applications) i.e., total 

thermal energy made available for processes and applications other thanthat is not used for

electric generation, mechanical output at the affected facility, or to directly enhance the 

performance of the affected facility (e.g., economizer output is not useful thermal output, but 

thermal energy used to reduce fuel moisture is considered useful thermal output). Useful 

Tthermal output for affected facilities with no condensate return (or other thermal energy input to 

the affected facility) or where measuring the energy in the condensate (or other thermal energy 

input to the affected facility) would not meaningfully impact the emission rate calculation is 

measured against the energy in the thermal output at SATP conditions. Affected facilities with 

meaningful energy in the condensate return (or other thermal energy input to the affected 

facility) must measure the energy in the condensate and subtract that energy relative to SATP 

conditions from the measured thermal output. this subpart means the energy in recovered thermal 

output measured against the energy in the thermal output at ISO conditions.

 
Page 41 of 45

Table 1 to Subpart TTTT of Part 60 – CO2 Emission Standards for Affected Facilities that 

Commenced Construction after January 8, 2014

Note: all numerical values have a minimum of 2 significant figures 

Affected Facility CO2 Emission Standard 

Stationary combustion turbine that has a base 

load rating heat input to the turbine engine of 

greater than 250 MW (850 MMBtu/h), that 

combusts over 90% natural gas on a heat input 

basis on a 3 year rolling average basis, and that 

supplieswhere net-electric sales consist of

more than one-third of its potential electric 

output and more than 219,000 MWh netelectric output to a utility distribution system 

on a 3 year rolling average basis. 

450 kilograms (kg) of CO2 per megawatt-hour 

(MWh) of gross output (1,000 lb/MWh) on a 

12-operating month rolling average 

Stationary combustion turbine that has a design 

heat input to the turbine engine greater than 73 

MW (250 MMBtu/h) and equal to or less than 

250 MW (850 MMBtu/h), that combusts over 

90% natural gas on a heat input basis on a 3 

year rolling average basis, and where netelectric sales consist of that supplies more than 

one-third of its potential electric output and 

more than 219,000 MWh net-electric output to 

a utility distribution system on a 3 year rolling 

average basis. 

500 kg of CO2 per MWh of gross output (1,100 

lb CO2/MWh) on a 12-operating month rolling 

average 

Steam generating unit that burns fossil fuel for 

more than 10.0 percent of the average annual 

heat input during a 3 year rolling average basis. 

500 kg of CO2 per MWh of gross energy 

output (1,100 lb CO2/MWh) on a 12-operating 

month rolling average basis; 

or 

480 kg of CO2 per MWh of gross energy 

output (1,050 lb CO2/MWh) on an 84-

operating month rolling average basis. 

Integrated gasification combined cycle (IGCC) 

facility that burns fossil fuel for more than 10.0 

percent of the average annual heat input during 

a 3 year rolling average basis. 

500 kg of CO2 per MWh of gross energy 

output (1,100 lb CO2/MWh) on a 12-operating 

month rolling average basis; 

or 

480 kg of CO2 per MWh of gross energy 

output (1,050 lb CO2/MWh) on an 84-

operating month rolling average basis. 

Stationary combustion turbine that either has a 

design heat input to the turbine engine of 73 

MW (250 MMBtu/h) or less, that combusts 

90% or less natural gas on a heat input basis on 

No emission standard 
Page 42 of 45

a 3 year rolling average basis, or where netelectric sales consist of that supplies one-third 

or less of its potential electric output or 

219,000 MWh or less net-electric output to a 

utility distribution system on a 3 year rolling 

average basis. 

Steam generating unit or IGCC facility that 

burns fossil fuel for 10.0 percent or less of the 

average annual heat input during a 3 year 

rolling average basis. 

No emission standard 

 
Page 43 of 45

Table 2 to Subpart TTTT of Part 60 – CO2 Emission Standards for Affected Facilities 

(Except Modified Steam Generating Units and IGCC Facilities Subject to an Approved 

CAA Section 111(d) Plan)1 that Commenced Reconstruction or Modification after 

[INSERT DATE OF PUBLICAITON IN THE FEDERAL REGISTER] 

Note: all numerical values have a minimum of 2 significant figures 

Affected Facility CO2 Emission Standard 

Stationary combustion turbine that has a base 

load rating heat input to the turbine engine of 

greater than 250 MW (850 MMBtu/h), that 

combusts over 90% natural gas on a heat 

input basis on a 3 year rolling average basis, 

and where net-electric sales consist of more 

than one-third of its potential electric output 

and more than 219,000 MWh net-electric 

output to a utility distribution system on a 3 

year rolling average basis. 

460 kilograms (kg) of CO2 per megawatt-hour 

(MWh) of gross output (1,000 lb/MWh) on a 

12-operating month rolling average 

Stationary combustion turbine that has a 

design heat input to the turbine engine greater 

than 73 MW (250 MMBtu/h) and equal to or 

less than 250 MW (850 MMBtu/h), that 

combusts over 90% natural gas on a heat 

input basis on a 3 year rolling average basis, 

and where net-electric sales consist of more 

than one-third of its potential electric output 

and more than 219,000 MWh net-electric 

output to a utility distribution system on a 3 

year rolling average basis. 

510 kg of CO2 per MWh of gross output 

(1,100 lb CO2/MWh) on a 12-operating 

month rolling average 

Stationary combustion turbine that either has 

a design heat input to the turbine engine of 73 

MW (250 MMBtu/h) or less, that combusts 

90% or less natural gas on a heat input basis 

on a 3 year rolling average basis, or where 

net-electric sales consist of one-third or less 

of its potential electric output or 219,000 

MWh or less net-electric output to a utility 

distribution system on a 3 year rolling average 

basis. 

No emission standard 

Steam generating unit or integrated 

gasification combined cycle (IGCC) facility 

that has a design heat input of 590 MW 

(2,000 MMBtu/h) or less and that burns fossil 

fuel for more than 10.0 percent of the average 

950 kg of CO2 per MWh of net energy output 

(2,100 lb CO2/MWh) on a 12-operating 

month rolling average basis; 

 

1

 The emission standards in Table 2 are not applicable to modified steam generating units and IGCC facilities 

subject to an approved CAA section 111(d) plan
Page 44 of 45

annual heat input during a 3 year rolling 

average basis. 

Steam generating unit or IGCC facility that 

has a design heat input greater than 590 MW 

(2,000 MMBtu/h) and that burns fossil fuel 

for more than 10.0 percent of the average 

annual heat input during a 3 year rolling 

average basis. 

860 kg of CO2 per MWh of net energy output 

(1,900 lb CO2/MWh) on a 12-operating 

month rolling average basis; 

Steam generating unit or IGCC facility that 

burns fossil fuel for 10.0 percent or less of the 

average annual heat input during a 3 year 

rolling average basis. 

No emission standard 

 
Page 45 of 45

Table 32 to Subpart TTTT of Part 60 – Applicability of Subpart A General Provisions to 

Subpart TTTT

General 

Provisions 

citation 

Subject of citation 

Applies to 

subpart 

TTTT 

Explanation 

§ 60.1 Applicability Yes 

§ 60.2 Definitions Yes Additional terms defined 

in § 60.5580 

§ 60.3 Units and Abbreviations Yes 

§ 60.4 Address Yes 

§ 60.5 

Determination of 

construction or 

modification 

Yes 

§ 60.6 Review of plans Yes 

§ 60.7 Notification and 

Recordkeeping Yes 

Only the requirements to 

submit the notification in § 

60.7(a)(1) and (a)(3) 

§ 60.8 Performance tests No 

§ 60.9 Availability of 

Information Yes 

§ 60.10 State authority Yes 

§ 60.11 

Compliance with 

standards and 

maintenance 

requirements 

No 

§ 60.12 Circumvention Yes 

§ 60.13 Monitoring requirements Yes 

§ 60.14 Modification No 

§ 60.15 Reconstruction No 

§ 60.16 Priority list No 

§ 60.17 Incorporations by 

reference Yes 

§ 60.18 General control device 

requirements No 

§ 60.19 General notification and 

reporting requirements Yes