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EO 12866_111(b) New-Mods 2060-AQ91 Final_20150507

6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60, 70, 71, and 98

[EPA-HQ-OAR-2013-0495; EPA-HQ-OAR-2013-0603; FRL-9930-66-OAR]

RIN 2060-AQ91

Standards of Performance for Greenhouse Gas Emissions from New, 

Modified, and Reconstructed Stationary Sources: Electric Utility 

Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

SUMMARY: The Environmental Protection Agency (EPA) is finalizing 

new source performance standards (NSPS) under Clean Air Act 

(CAA) section 111(b) that, for the first time, will establish 

standards for emissions of carbon dioxide (CO2) for newly 

constructed, modified, and reconstructed affected fossil fuelfired electric utility generating units (EGUs). This action 

establishes separate standards of performance for fossil fuelfired electric utility steam generating units and fossil fuelfired stationary combustion turbines. This action also addresses 

related permitting and reporting issues. In a separate action, 

under CAA section 111(d), the EPA is issuing final emission 
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guidelines for states to use in developing plans to limit CO2

emissions from existing fossil fuel-fired EGUs. 

DATES: This final rule is effective on [insert date 60 days 

after date of publication in the Federal Register]. The 

incorporation by reference of certain publications listed in the 

rule is approved by the Director of the Federal Register as of 

[insert date of publication in the Federal Register].

ADDRESSES: The EPA has established dockets for this action under 

Docket ID No. EPA-HQ-OAR-2013-0495 (Standards of Performance for 

Greenhouse Gas Emissions from New Stationary Sources: Electric 

Utility Generating Units) and Docket ID No. EPA-HQ-OAR-2013-0603 

(Carbon Pollution Standards for Modified and Reconstructed 

Stationary Sources: Electric Utility Generating Units). All 

documents in the dockets are listed on the www.regulations.gov 

Web site. Although listed in the index, some information is not 

publicly available, e.g., Confidential Business Information or 

other information whose disclosure is restricted by statute. 

Certain other material, such as copyrighted material, will be 

publicly available only in hard copy. Publicly available docket 

materials are available either electronically in 

www.regulations.gov or in hard copy at the EPA Docket Center 

(EPA/DC), Room 3334, EPA WJC West Building, 1301 Constitution 

Ave. NW, Washington, DC. The Public Reading Room is open from 

8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal 
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holidays. The telephone number for the Public Reading Room is 

(202) 566-1744, and the telephone number for the Air Docket is 

(202) 566-1742. 

FOR FURTHER INFORMATION CONTACT: Dr. Nick Hutson, Energy 

Strategies Group, Sector Policies and Programs Division (D243-

01), U.S. EPA, Research Triangle Park, NC 27711; telephone 

number (919) 541-2968, facsimile number (919) 541-5450; email 

address: hutson.nick@epa.gov or Mr. Christian Fellner, Energy 

Strategies Group, Sector Policies and Programs Division (D243-

01), U.S. EPA, Research Triangle Park, NC 27711; telephone 

number (919) 541-4003, facsimile number (919) 541-5450; email 

address: fellner.christian@epa.gov.

SUPPLEMENTARY INFORMATION: Acronyms. A number of acronyms and 

chemical symbols are used in this preamble. While this may not 

be an exhaustive list, to ease the reading of this preamble and 

for reference purposes, the following terms and acronyms are 

defined as follows:

AB Assembly Bill

AEO Annual Energy Outlook

AEP American Electric Power

ANSI American National Standards Institute

ASME American Society of Mechanical Engineers

ASTM American Society for Testing of Materials

BACT Best Available Control Technology

BDT Best Demonstrated Technology

BSER Best System of Emission Reduction

Btu/kWh British Thermal Units per Kilowatt-hour

Btu/lb British Thermal Units per Pound

CAA Clean Air Act

CAIR Clean Air Interstate Rule
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CBI Confidential Business Information

CCS Carbon Capture and Storage (or Sequestration)

CDX Central Data Exchange

CEDRI Compliance and Emissions Data Reporting Interface

CEMS Continuous Emissions Monitoring System

CFB Circulating Fluidized Bed

CH4 Methane

CHP Combined Heat and Power

CO2 Carbon Dioxide

CSAPR Cross-State Air Pollution Rule

DOE Department of Energy

DOT Department of Transportation

ECMPS Emissions Collection and Monitoring Plan System

EERS Energy Efficiency Resource Standards

EGU Electric Generating Unit

EIA Energy Information Administration

EO Executive Order

EOR Enhanced Oil Recovery

EPA Environmental Protection Agency

FB Fluidized Bed

FGD Flue Gas Desulfurization

FOAK First-of-a-kind

FR Federal Register

GHG Greenhouse Gas

GHGRP Greenhouse Gas Reporting Program

GPM Gallons per Minute

GS Geologic Sequestration

GW Gigawatts

H2 Hydrogen Gas

HAP Hazardous Air Pollutant

HFC Hydrofluorocarbon

HRSG Heat Recovery Steam Generator

IGCC Integrated Gasification Combined Cycle

IPCC Intergovernmental Panel on Climate Change

IPM Integrated Planning Model

IRPs Integrated Resource Plans

kg/MWh Kilogram per Megawatt-hour

kJ/kg Kilojoules per Kilogram

kWh Kilowatt-hour

lb CO2/MMBtu Pounds of CO2 per Million British Thermal Unit

lb CO2/MWh Pounds of CO2 per Megawatt-hour

lb CO2/yr Pounds of CO2 per Year

lb/lb-mole Pounds per Pound-Mole

LCOE Levelized Cost of Electricity

MATS Mercury and Air Toxic Standards

MMBtu/hr Million British Thermal Units per Hour

MRV Monitoring, Reporting, and Verification
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MW Megawatt

MWe Megawatt Electrical

MWh Megawatt-hour

MWh-g Megawatt-hour gross

MWh-n Megawatt-hour net

N2O Nitrous Oxide

NAAQS National Ambient Air Quality Standards

NAICS North American Industry Classification System

NAS National Academy of Sciences

NETL National Energy Technology Laboratory

NGCC Natural Gas Combined Cycle

NOAK n

th-of-a-kind 

NRC National Research Council

NSPS New Source Performance Standards

NSR New Source Review

NTTAA National Technology Transfer and Advancement Act

O2 Oxygen Gas

OMB Office of Management and Budget

PC Pulverized Coal

PFC Perfluorocarbon

PM Particulate Matter

PM2.5 Fine Particulate Matter

PRA Paperwork Reduction Act

PSD Prevention of Significant Deterioration

PUC Public Utilities Commission

RCRA Resource Conservation and Recovery Act

RFA Regulatory Flexibility Act

RGGI Regional Greenhouse Gas Initiative

RIA Regulatory Impact Analysis

RPS Renewable Portfolio Standard

RTC Response to Comments

RTP Response to Petitions

SBA Small Business Administration

SCC Social Cost of Carbon

SCR Selective Catalytic Reduction

SCPC Supercritical Pulverized Coal

SDWA Safe Drinking Water Act

SF6 Sulfur Hexafluoride

SIP State Implementation Plan

SNCR Selective Non-Catalytic Reduction

SO2 Sulfur Dioxide

SSM Startup, Shutdown, and Malfunction

Tg Teragram (one trillion (1012) grams)

Tpy Tons per Year

TSD Technical Support Document

TTN Technology Transfer Network

UIC Underground Injection Control
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UMRA Unfunded Mandates Reform Act of 1995

U.S. United States

USDW Underground Source of Drinking Water

USGCRP U.S. Global Change Research Program

VCS Voluntary Consensus Standard

WGS Water Gas Shift 

WWW World Wide Web

Organization of This Document. The information presented in 

this preamble is organized as follows:

I. General Information

A. Executive Summary 

B. Does this action apply to me?

C. Where can I get a copy of this document?

D. Judicial Review

E. How is this preamble organized?

II. Background

A. Climate Change Impacts from GHG Emissions

B. GHG Emissions from Fossil Fuel-fired EGUs

C. The Utility Power Sector 

D. Statutory Background

E. Regulatory Background

F. Development of Carbon Pollution Standards for Fossil Fuelfired Electric Utility Generating Units

G. Stakeholder Engagement and Public Comments on the Proposals

III. Regulatory Authority, Affected EGUs and Their Standards, 

and Legal Requirements

A. Authority to Regulate Carbon Dioxide from Fossil Fuel-fired 

EGUs

B. Treatment of Categories and Codification in the Code of 

Federal Regulations

C. Affected Units

D. Units Not Covered by this Final Rule

E. Coal Refuse

F. Format of the Output-based Standard

G. CO2 Emissions Only

H. Legal Requirements for Establishing Emission Standards

I. Severability

J. Certain Projects under Development

IV. Summary of Final Standards for Newly Constructed, Modified, 

and Reconstructed Fossil Fuel-fired Electric Utility Steam 

Generating Units

A. Applicability Requirements and Rationale

B. Best System of Emission Reduction

C. Final Standards of Performance
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V. Rationale for Final Standards for Newly Constructed Fossil 

Fuel-fired Electric Utility Steam Generating Units

A. Factors Considered in Determining the BSER

B. Highly Efficient SCPC EGU Implementing Partial CCS as the 

BSER for Newly Constructed Steam Generating Units

C. Rationale for the Final Emission Standards

D. Post-Combustion Carbon Capture

E. Pre-Combustion Carbon Capture

F. Vendor Guarantees, Industry Statements, Academic Literature, 

and Commercial Availability

G. Response to Key Comments on the Adequacy of the Technical 

Feasibility Demonstration 

H. Consideration of Costs

I. Key Comments Regarding the EPA’s Consideration of Costs

J. Achievability of the Final Standards

K. Emission Reductions Utilizing Partial CCS

L. Further Development and Deployment of CCS Technology

M. Technical and Geographic Aspects of Disposition of Captured 

CO2

N. Final Requirements for Disposition of Captured CO2

O. Non-air Quality Impacts and Energy Requirements

P. Options That Were Considered by the EPA but Were Ultimately 

Not Determined to Be the BSER

Q. Summary

VI. Rationale for Final Standards for Modified Fossil Fuel-fired 

Electric Utility Steam Generating Units

A. Rationale for Final Applicability Criteria for Modified Steam 

Generating Units

B. Identification of the Best System of Emission Reduction

C. BSER Criteria

VII. Rationale for Final Standards for Reconstructed Fossil 

Fuel-fired Electric Utility Steam Generating Units

A. Rationale for Final Applicability Criteria for Reconstructed 

Sources

B. Identification of the Best System of Emission Reduction

VIII. Summary of Final Standards for Newly Constructed and 

Reconstructed Stationary Combustion Turbines

A. Applicability Requirements

B. Best System of Emission Reduction

C. Final Emission Standards

D. Significant Differences between Proposed and Final Combustion 

Turbine Provisions

IX. Rationale for Final Standards for Newly Constructed and 

Reconstructed Stationary Combustion Turbines

A. Applicability

B. Subcategories

C. Identification of the Best System of Emission Reduction
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D. Achievability of the Final Standards

X. Summary of Other Final Requirements for Newly Constructed, 

Modified, and Reconstructed Fossil Fuel-fired Electric Utility 

Steam Generating Units and Stationary Combustion Turbines

A. Startup, Shutdown, and Malfunction Requirements

B. Continuous Monitoring Requirements

C. Emissions Performance Testing Requirements

D. Continuous Compliance Requirements

E. Notification, Recordkeeping, and Reporting Requirements

XI. Consistency between BSER Determinations for This Rule and 

the Rule for Existing EGUs

A. Newly Constructed Steam Generating Units

B. New Combustion Turbines

C. Modified and Reconstructed Steam and NGCC Units 

XII. Interactions with Other EPA Programs and Rules

A. Overview

B. Applicability of Tailoring Rule Thresholds under the PSD 

Program

C. Implications for BACT Determinations under PSD

D. Implications for Title V Program

E. Implications for Title V Fee Requirements for GHGs

F. Interactions with Other EPA Rules

XIII. Impacts of this Action

A. What are the air impacts?

B. Endangered Species Act

C. What are the energy impacts?

D. What are the water and solid waste impacts?

E. What are the compliance costs?

F. What are the economic and employment impacts?

G. What are the benefits of the final standards?

XIV. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review

B. Paperwork Reduction Act (PRA)

C. Regulatory Flexibility Act (RFA)

D. Unfunded Mandates Reform Act (UMRA)

E. Executive Order 13132: Federalism

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

G. Executive Order 13045: Protection of Children From 

Environmental Health Risks and Safety Risks

H. Executive Order 13211: Actions Concerning Regulations that 

Significantly Affect Energy Supply, Distribution, or Use

I. National Technology Transfer and Advancement Act (NTTAA) and 1 

CFR part 51
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J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

K. Congressional Review Act (CRA)

XV. Withdrawal of Proposed Standards for Certain Modified 

Sources

XVI. Statutory Authority

I. General Information

A. Executive Summary

1. Purpose of the Regulatory Action 

In this final action the EPA is establishing standards that

limit greenhouse gas (GHG) emissions from newly constructed, 

modified, and reconstructed fossil fuel-fired electric utility 

steam generating units and stationary combustion turbines, 

following the issuance of proposals for such standards and an 

accompanying Notice of Data Availability.

On June 25, 2013, in conjunction with the announcement of 

his Climate Action Plan (CAP), President Obama issued a 

Presidential Memorandum directing the EPA to issue a proposal to 

address carbon pollution from new power plants by September 30, 

2013, and to issue “standards, regulations, or guidelines, as 

appropriate, which address carbon pollution from modified, 

reconstructed, and existing power plants.” Pursuant to authority 

in section 111(b) of the CAA, on September 20, 2013, the EPA 

issued proposed carbon pollution standards for newly constructed 

fossil fuel-fired power plants. The proposal was published in 

the Federal Register on January 8, 2014 (79 FR 1430; “January 
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2014 proposal”).1 In that proposal, the EPA proposed to limit 

emissions of CO2 from newly constructed fossil fuel-fired 

electric utility steam generating units and newly constructed 

natural gas-fired stationary combustion turbines. 

The EPA subsequently issued a Notice of Data Availability 

(NODA) in which the EPA solicited comment on its initial 

interpretation of provisions in the Energy Policy Act of 2005 

(EPAct05) and associated provisions in the Internal Revenue Code 

(IRC) and also solicited comment on a companion Technical 

Support Document (TSD) that addressed these provisions’ 

relationship to the factual record supporting the proposed rule. 

79 FR 10750 (February 26, 2014).

On June 2, 2014, the EPA proposed standards of performance, 

also pursuant to CAA section 111(b), to limit emissions of CO2

from modified and reconstructed fossil fuel-fired electric 

utility steam generating units and natural gas-fired stationary 

combustion turbines. 79 FR 34960 (June 18, 2014) (“June 2014 

proposal”). Specifically, the EPA proposed standards of 

performance for: (1) modified fossil fuel-fired steam generating 

units, (2) modified natural gas-fired stationary combustion 

 

1 The EPA previously proposed performance standards for newly 

reconstructed fossil fuel-fired EGUs in April 2012 (77 FR 

22392). In that action, the EPA proposed standards for steam 

generating units and natural gas-fired combustion turbines based 

on a single Best System of Emission Reduction determination. On 

January 8, 2014, the EPA withdrew that proposal (79 FR 1352). 
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turbines, (3) reconstructed fossil fuel-fired steam generating 

units, and (4) reconstructed natural gas-fired stationary 

combustion turbines.

In this action, the EPA is issuing final standards of 

performance to limit emissions of GHG pollution manifested as CO2

from newly constructed, modified, and reconstructed fossil fuelfired electric utility steam generating units (i.e., utility 

boilers and integrated gasification combined cycle (IGCC) units) 

and from newly constructed and reconstructed stationary 

combustion turbines. Consistent with the requirements of CAA 

section 111(b), these standards reflect the degree of emission 

limitation achievable through the application of the best system 

of emission reduction (BSER) that the EPA has determined has 

been adequately demonstrated for each type of unit. These final

standards are codified in 40 CFR part 60, subpart TTTT, a new 

subpart specifically created for CAA 111(b) standards of 

performance for GHG emissions from fossil fuel-fired EGUs.

In a separate action that affects the same source category, 

the EPA is issuing final emission guidelines under CAA section 

111(d) for states to use in developing plans to limit CO2

emissions from existing fossil fuel-fired EGUs. Pursuant to 

those guidelines, states must submit plans to the EPA following 

a schedule set by the guidelines.
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The EPA received numerous comments and conducted extensive 

outreach to stakeholders for this rulemaking. After careful 

consideration of public comments and input from a variety of 

stakeholders, the final standards of performance in this action 

reflect certain changes from the proposals. Comments considered 

include written comments that were submitted during the public 

comment period and oral testimony provided during the public 

hearing for the proposed standards.

2. Summary of Major Provisions and Changes to the Proposed 

Standards

The BSER determinations and final standards of performance 

for affected newly constructed, modified, and reconstructed EGUs 

are summarized in Table 1 and discussed in more detail below. 

The final standards for new, modified, and reconstructed EGUs 

apply to sources that commenced construction – or modification 

or reconstruction, as appropriate – on or after the date of 

publication of corresponding proposed standards.2 The final 

standards for newly constructed fossil fuel-fired EGUs apply to 

those sources that commenced construction on or after the date 

of publication of the proposed standards, January 8, 2014. The 

final standards for modified and reconstructed fossil fuel-fired 

EGUs apply to those sources that modify or reconstruct on or 

 

2 See CAA section 111(a)(2).
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after the date of publication of the proposed standards, June 

18, 2014.

Table 1. Summary of BSER and Final Standards for Affected EGUs

Affected EGUs BSER Final Standards of 

Performance

Newly 

Constructed 

Fossil FuelFired Steam 

Generating Units

Efficient new 

supercritical 

pulverized coal 

(SCPC) utility 

boiler implementing 

partial carbon 

capture and storage 

(CCS)

1,400 lb CO2/MWh-g.

Modified Fossil 

Fuel-Fired Steam 

Generating Units

Most efficient 

generation at the 

affected EGU

achievable through a 

combination of best 

operating practices 

and equipment 

upgrades 

Sources making 

modifications

resulting in an increase 

in CO2 hourly emissions 

of more than 10 percent 

are required to meet a 

unit-specific emission 

limit determined by the 

unit’s best historical 

annual CO2 emission rate 

(from 2002 to the date 

of the modification); 

the emission limit will 

be no more stringent

than:

1. 1,800 lb CO2/MWh-g for 

sources with heat 

input > 2,000 MMBtu/h.

OR

2. 2,000 lb CO2/MWh-g for 

sources with heat 

input ≤ 2,000 MMBtu/h.

Reconstructed Most efficient 1. Sources with heat 

input > 2,000 MMBtu/h 
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Fossil FuelFired Steam 

Generating Units

generating 

technology

at the 

affected

source

(supercritical steam 

conditions for the 

larger; and 

subcritical 

conditions for the 

smaller)

are required to meet 

an emission limit of 

1,800 lb CO2/MWh-g.

2. Sources with heat 

input ≤ 2,000 MMBtu/h 

are required to meet 

an emission limit of 

2,000 lb CO2/MWh-g.

Newly 

Constructed and 

Reconstructed 

Fossil FuelFired Stationary 

Combustion 

Turbines

Efficient NGCC 

technology for base 

load natural gasfired units and 

clean fuels for nonbase load and multifuel-fired units3

1. 1,000 lb CO2/MWh-g or

1,030 lb CO2/MWh-n for 

base load natural gasfired units.

2. 120 lb CO2/MMBtu for 

non-base load natural 

gas-fired units.

3. 120 to 160 lb 

CO2/MMBtu for multifuel-fired units.4

 

3 The term "multi-fuel-fired" refers to a stationary combustion 

turbine that is physically connected to a natural gas pipeline, 

but that burns a fuel other than natural gas for 10 percent or 

more of the unit's heat input capacity during the 12-operatingmonth compliance period.

4 The emission standard for combustion turbines co-firing natural 

gas with other fuels shall be determined at the end of each 

operating month based on the amount of co-fired natural gas.

Units only burning natural gas with other fuels with a 

relatively consistent chemical composition and an emission 

factor of 160 lb CO2/MMBtu or less (e.g., natural gas, distillate 

oil, etc.) only need to maintain records of the fuels burned at 

the unit to demonstrate compliance. Units burning fuels with 

variable chemical composition or with an emission factor greater 

than 160 lb CO2/MMBtu (e.g., residual oil) must conduct periodic 

fuel sampling and testing to determine the overall CO2 emission 

rate. 
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a. Fossil fuel-fired electric utility steam generating units

This action establishes standards of performance for newly 

constructed fossil fuel-fired steam generating units5 based on

the performance of a new highly efficient SCPC EGU implementing

post-combustion partial carbon capture and storage (CCS)

technology, which the EPA determines to be the BSER for these 

sources. After consideration of a wide range of comments,

technical input received on the availability, technical 

feasibility, and cost of CCS implementation, and publicly 

available information about projects that are implementing or 

planning to implement CCS, the EPA confirms its proposed 

determination that CCS technology is available and technically 

feasible to implement at fossil fuel-fired steam generating 

units. However, the EPA’s final standard reflects the 

consideration of legitimate concerns regarding the cost to 

implement available CCS technology on a new steam generating 

unit. Accordingly, the EPA is finalizing an emission standard 

for newly constructed fossil fuel-fired steam generating units 

at 1,400 lb CO2/MWh-g, a level that is less stringent than the 

proposed limitation of 1,100 lb CO2/MWh-g. This final standard 

reflects our identification of the BSER for such units to be a 

 

5 Also referred to as just “steam generating units” or as 

“utility boilers and IGCC units”. These are units that are 

covered under 40 CFR part 60, subpart Da for criteria 

pollutants.
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lower level of partial CCS than we identified as the basis of 

the proposed standards – one that we conclude better represents 

the requirement that the BSER be implementable at reasonable 

cost.

The EPA proposed that the BSER for newly constructed steam 

generating EGUs was highly efficient new generating technology 

(i.e., a supercritical utility boiler or IGCC unit) implementing 

partial CCS technology to achieve CO2 emission reductions 

resulting in an emission limit of 1,100 lb CO2/MWh-g.6

The BSER for newly constructed steam generating EGUs in the 

final rule is very similar to that in the January 2014 proposal. 

In this final action, the EPA finds that a highly efficient new 

supercritical pulverized coal (SCPC) utility boiler EGU 

implementing partial CCS to the degree necessary to achieve an 

emission of 1,400 lb CO2/MWh-g is the BSER. Contrary to the 

January 2014 proposal, the EPA finds that IGCC technology –

either with natural gas co-firing or implementing partial CCS –

is not part of the BSER, but recognizes that IGCC technology can 

serve as an alternative method of compliance. 

The EPA finds that a highly efficient SCPC implementing 

partial CCS is the BSER because CCS technology has been 

 

6 Using the most recent data on partial capture rates to meet an 

emission standard of 1,100 lb CO2/MWh-gross, about 35 percent 

capture would be required at an SCPC unit and about 22 percent 

capture would be required at an IGCC unit.
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demonstrated to be technically feasible and is in use or under 

construction in various industrial sectors, including the power 

generation sector. For example, the Boundary Dam Unit #3 CCS 

project in Saskatchewan, Canada is a full-scale, fully 

integrated CCS project that is currently operating and is 

designed to capture more than 90 percent of the CO2 from the 

lignite-fired boiler. A newly constructed, highly efficient SCPC

utility boiler burning bituminous coal will be able to meet this

final standard of performance by capturing and storing 

approximately 16 percent of the CO2 produced from the facility. A 

newly constructed, highly efficient SCPC utility boiler burning 

subbituminous coal or dried lignite7 will be able to meet this

final standard of performance by capturing and storing 

approximately 23 percent of the CO2 produced from the facility. 

As an alternative compliance option, utilities and project 

developers will also be able to construct new steam generating 

units (both utility boilers and IGCC units) that meet the final 

standard of performance by co-firing with natural gas. This 

final standard of performance for newly constructed fossil fuel-

 

7 For a summary of lignite drying technologies, see “Technoeconomics of modern pre-drying technologies for

lignite-fired power plants” available at www.ieacoal.org.uk/documents/83436/9095/Techno-economics-of-modern-predrying-technologies-for-lignite-fired-power-plants,-CCC/241; 

“Drying the lignite prior to combustion in the boiler is thus an 

effective way to increase the thermal efficiencies and reduce 

the CO2 emissions from lignite-fired power plants.”
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fired steam generating units provides a clear and achievable 

path forward for the construction of such sources while 

addressing GHG emissions and supporting technological 

innovation. The standard of 1,400 lb CO2/MWh-g is achievable by 

fossil fuel-fired steam generating units for all fuel types, 

under a wide range of conditions, and throughout the United 

States.

We note that identifying a highly efficient new SCPC EGU 

implementing partial CCS as the BSER provides a path forward for 

new fossil fuel-fired steam generation in the current market 

context. Numerous studies have predicted that few new fossil

fuel-fired steam generating units will be constructed in the 

future. These analyses identify a range of factors unrelated to 

this rulemaking, including low electricity demand growth, highly 

competitive natural gas prices, and increases in the supply of 

renewable energy. The EPA recognizes that, in certain 

circumstances, there may be interest in building fossil fuelfired steam generating units despite these market conditions. In

particular, utilities and project developers may build new 

fossil fuel-fired steam generating EGUs in order to achieve or 

maintain fuel diversity within generating fleets, as a hedge 

against the possibility of natural gas prices far exceeding 

projections, or to co-produce both power and chemicals, 

including capturing CO2 for use in enhanced oil recovery (EOR)
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projects.

8 As regulatory history has shown, identifying a new 

highly efficient SCPC EGU implementing partial CCS as the BSER 

in this rule is likely to further boost research and development

in CCS technologies, making the implementation even more 

efficacious and cost-effective, while providing a competitive, 

low emission future for fossil fuel-fired steam generation.

The EPA is also issuing final standards for steam 

generating units that implement “large modifications,” (i.e.,

modifications resulting in an increase in hourly CO2 emissions of 

more than 10 percent when compared to the source’s highest 

hourly emissions in the previous 5 years).9 The EPA is not 

 

8 As the EIA has stated:

Policy-related factors, such as environmental 

regulations and investment or production tax credits 

for specified generation sources, can also impact 

investment decisions. Finally, although levelized cost 

calculations are generally made using an assumed set

of capital and operating costs, the inherent 

uncertainty about future fuel prices and future 

policies may cause plant owners or investors who 

finance plants to place a value on portfolio 

diversification. While EIA considers many of these 

factors in its analysis of technology choice in the 

electricity sector, these concepts are not included in 

LCOE or LACE calculations.

http://www.eia.gov/forecasts/aeo/electricity_generation.cfm

9 40 CFR 60.14(h) – “No physical change, or change in the method 

of operation, at an existing electric utility steam generating 

unit shall be treated as a modification for the purposes of this 

section provided that such change does not increase the maximum 

hourly emissions of any pollutant regulated under this section 
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issuing final standards, at this time, for steam generating 

units that implement “small modifications” (i.e., modifications 

resulting in an increase in hourly CO2 emissions of less than or 

equal to 10 percent when compared to the source’s highest hourly 

emissions in the previous 5 years).

The standards of performance for modified steam generating 

units that make large modifications are based on each affected 

unit’s own best potential performance as the BSER. Specifically, 

such a modified steam generating unit will be required to meet a 

unit-specific CO2 emission limit determined by that unit's best 

demonstrated historical performance (in the years from 2002 to 

the time of the modification).10 The EPA has determined that this 

standard based on each unit’s own best potential performance can 

be met through a combination of best operating practices and 

equipment upgrades and that these steps can be implemented costeffectively at the time when a source is undertaking a large 

modification. To account for facilities that have already 

implemented best practices and equipment upgrades, the final 

rule also specifies that modified facilities will not have to 

meet an emission standard more stringent than the corresponding 

 

above the maximum hourly emissions achievable at that unit 

during the 5 years prior to the change.”

10 For the 2002 reporting year the EPA introduced new automated 

checks in the software that integrated automated quality 

assurance (QA) checks on the hourly data. Thus, the EPA believes 

that the data from 2002 and forward are of higher quality.
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standard for reconstructed steam generating units (i.e., 1,800 

lb CO2/MWh-g for units with heat input greater than 2,000 MMBtu/h 

and 2,000 lb CO2/MWh-g for units with heat input less than or 

equal to 2,000 MMBtu/h).

The final standards for steam generating units implementing 

large modifications are similar to the proposed standards for 

such units. In the proposal, we suggested that the standard 

should be based on when the modification is undertaken (i.e., 

before being subject to requirements under a CAA section 111(d) 

state plan or after being subject to such a plan). We also 

suggested that for units that undertake modifications prior to 

becoming subject to an approved CAA section 111(d) state plan, 

the standard should be its best historical performance plus an 

additional two percent reduction. In response to comments on the 

proposal, we are not finalizing separate standards that are 

dependent upon when the modification takes place, nor are we 

finalizing the proposed additional two percentage reduction. 

The EPA is not promulgating final standards of performance 

for, and is withdrawing the proposed standards for steam 

generating sources that make modifications resulting in an 

increase of hourly CO2 emissions of less than or equal to 10 

percent (see Section XV of this preamble). As we indicated in 

the proposal, the EPA has been notified of very few 

modifications for criteria pollutant emissions from the power 
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sector to which NSPS requirements have applied. As such, we 

expect that there will be few NSPS modifications for GHG 

emissions as well. Even so, we also recognize (and we discuss in 

this preamble) that the power sector is undergoing significant 

change and realignment in response to a variety of influences 

and incentives in the industry. We do not have sufficient 

information at this time, however, to anticipate the types of 

modifications, if any, that may result from these changes. In

particular, we do not have sufficient information about the 

types of modifications, if any, that would result in increases 

in CO2 emissions of 10 percent or less, and what the appropriate 

standard for such sources would be. Therefore, we conclude that 

it is prudent to delay issuing standards for sources that 

undertake small modifications (i.e., those resulting in an 

increase in CO2 emissions of less than or equal to 10 percent).

For reconstructed steam generating units, the EPA is 

finalizing standards based on the performance of the most 

efficient generating technology for these types of units as the 

BSER (i.e., reconstructing the boiler if necessary to use steam 

with higher temperature and pressure, even if the boiler was not 

originally designed to do so).

11 The emission standard for these 

 

11 Steam with higher temperature and pressure has more thermal 

energy that can be more efficiently converted to electrical 

energy.
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sources is 1,800 lb CO2/MWh-g for large sources, (i.e. those with 

a heat input rating of greater than 2,000 MMBtu/h) or 2,000 lb 

CO2/MWh-g for small sources (i.e., those with a heat input rating 

of 2,000 MMBtu/h or less). The difference in the standards for 

larger and smaller units is based on greater availability of 

higher pressure/temperature steam turbines (e.g., supercritical 

steam turbines) for larger units. The standards can also be met 

through other non-BSER options, such as natural gas co-firing.

b. Stationary combustion turbines

This action also finalizes standards of performance for 

newly constructed and reconstructed stationary combustion 

turbines. In the January 2014 proposal for newly constructed 

EGUs, the EPA proposed that natural gas-fired stationary 

combustion turbines (i.e., turbines combusting over 90 percent 

natural gas) would be subject to a standard of performance for 

CO2 emissions if they are constructed for the purpose of 

supplying and actually annually supply to the grid (1) one-third 

or more of their potential electric output12 and (2) more than

219,000 MWh,

13 based on a three-year rolling average. We refer to 

units that operate above the electric sales thresholds as "base

 

12 We refer to thresholds related to an EGU's actual annual 

electrical sales (as a fraction of potential annual output) as

"percentage electric sales criteria."

13 We refer to thresholds related to an EGU's actual annual 

electrical sales in megawatt-hours as "total electric sales 

criteria." 
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load units," and we refer to units that operate below these 

thresholds as "non-base load units."

In the January 2014 proposal for newly constructed 

combustion turbines, the EPA proposed standards for two 

subcategories of base load natural gas-fired stationary 

combustion turbines. The proposed standard for small combustion 

turbines (units with base load ratings less than or equal to 850 

MMBtu/h) was 1,100 lb CO2/MWh-g. The proposed standard for large 

combustion turbines (units with base load ratings greater than 

850 MMBtu/h) was 1,000 lb CO2/MWh-g. The EPA did not propose 

standards for non-base load units.

In the June 2014 proposal for modified and reconstructed 

combustion turbines, the EPA solicited comment on alternative 

approaches for establishing applicability and subcategorization 

criteria, including (1) eliminating the “constructed for the 

purpose of supplying” qualifier for the total electric sales and 

percentage electric sales criteria, (2) eliminating the 219,000 

MWh total electric sales criterion altogether, (3) replacing the 

fixed percentage electric sales criterion with a variable 

percentage electric sales criterion (i.e., the sliding-scale 

approach14), and (4) eliminating the proposed small and large 

 

14 The sliding-scale approach determines a unit-specific 

percentage electric sales threshold equivalent to a unit’s net 

design efficiency (the maximum value is capped at 50 percent).
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subcategories for base load natural gas-fired combustion 

turbines. These proposed applicability requirements were 

intended to exclude combustion turbines that are used for the 

purpose of meeting peak power demand, as opposed to those that 

are used to meet base load power demand. 

In both proposals, the EPA also solicited comment on a 

broad applicability approach that would include non-base load 

natural gas-fired units (primarily simple cycle combustion 

turbines) and multi-fuel-fired units (primarily distillate oilfired combustion turbines) in the general applicability of

subpart TTTT. As part of the broad applicability approach, the 

EPA solicited comment on imposing “no emission standard” or 

establishing separate numerical limits for these two 

subcategories.

In this action, the EPA is finalizing a variation of the

approaches put forward in the January 2014 proposal for new 

sources and the June 2014 proposal for modified and 

reconstructed sources. Based on our review of public comments 

related to the proposed subcategories for small and large

combustion turbines and our additional data analyses, we have 

determined that there is no need to set two separate standards

for different size combustion turbines for base load natural 

gas-fired combustion turbines. The EPA has determined that all 

sizes of affected newly constructed and reconstructed stationary 
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combustion turbines can achieve the final standards. For newly 

constructed and reconstructed base load natural gas-fired

stationary combustion turbines, the EPA is finalizing a standard 

of 1,000 lb CO2/MWh-g based on efficient natural gas combined 

cycled (NGCC) technology as the BSER. Alternatively, owners and 

operators of base load natural gas-fired combustion turbines may 

elect to comply with a standard based on net output of 1,030 lb 

CO2/MWh-n.

The EPA is eliminating the 219,000 MWh total annual 

electric sales criterion for non-CHP units. In addition, the EPA 

is finalizing the sliding-scale approach for deriving the unitspecific, percentage electric sales threshold above which a 

combustion turbine transitions from the subcategory for non-base 

load units to the subcategory for base load units. For newly 

constructed and reconstructed non-base load natural gas-fired

stationary combustion turbines, the EPA is finalizing the 

combustion of clean fuels (natural gas with a small allowance 

for distillate oil) as the BSER with a corresponding heat inputbased standard of 120 lb CO2/MMBtu. This standard of performance 

will apply to the vast majority of simple cycle combustion 

turbines. The EPA is finalizing a heat input-based clean fuels 

standard because we have insufficient information at this time

to set a uniform output-based standard that can be achieved by 

all new and reconstructed non-base load units. 
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In addition, for newly constructed and reconstructed multifuel-fired stationary combustion turbines, the EPA is finalizing 

an input-based standard of 120 to 160 lb CO2/MMBtu based on the 

combustion of clean fuels as the BSER.16 The EPA has similarly 

determined that it has insufficient information at this time to 

set a uniform output-based standard for stationary combustion 

turbines that operate with significant quantities of a fuel 

other than natural gas.

We are not promulgating final standards of performance for 

stationary combustion turbines that make modifications at this 

time. We are simultaneously withdrawing the proposed standards 

for modifications (see Section XV of this preamble). As we 

indicated in the proposal, sources from the power sector have 

notified the EPA of very few NSPS modifications, and we expect 

that there will be few NSPS modifications for CO2 emissions as 

well. Moreover, our decision to eliminate the subcategories for 

small and large EGUs and set a single standard of 1,000 lb 

CO2/MWh-g has raised questions as to whether smaller existing 

combustion turbines that undertake a modification can meet this 

standard. As a result, we have concluded that it is prudent to 

 

16 Combustion turbines co-firing natural gas with other fuels 

shall determine fuel-based site-specific standards at the end of 

each operating month. The site-specific standards depend on the 

amount of co-fired natural gas.
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delay issuing standards for sources that undertake modifications

until we can gather more information.

A more detailed discussion of the final standards of 

performance for stationary combustion turbines, the 

applicability criteria, and the comments that influenced the 

final standards is provided in Sections VIII and IX of this 

preamble.

3. Costs and Benefits

As explained in the regulatory impact analysis (RIA) for 

this final rule, available data – including utility 

announcements and Energy Information Administration (EIA)

modeling - indicate that, even in the absence of this rule, (i) 

existing and anticipated economic conditions are such that few, 

if any, fossil fuel-fired steam-generating EGUs will be built in 

the foreseeable future, and (ii) utilities and project 

developers are expected to choose new generation technologies 

(primarily NGCC) that would meet the final standards and 

renewable generating sources that are not affected by these 

final standards. These projections are consistent with utility 

announcements and EIA modeling that indicate that new units are 

likely to be NGCC and that any coal-fired steam generating units 

built between now and 2030 would have CCS, even in the absence 
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of this rule.17 Therefore, based on the analysis presented in 

Chapter 4 of the RIA, the EPA projects that this final rule will 

result in negligible CO2 emission changes, quantified benefits, 

and costs by 2022 as a result of the performance standards for 

newly constructed EGUs.18 However, as noted earlier, for a 

variety of reasons, some companies may consider coal-fired steam 

generating units that the modeling does not anticipate. Thus, in 

Chapter 5 of the RIA, we also present an analysis of the 

project-level costs of a newly constructed coal-fired steam 

generating unit with partial CCS that meets the requirements of 

this final rule alongside the project-level costs of a newly 

constructed coal-fired unit without CCS. This analysis indicates 

that the quantified benefits of the standards of performance 

would exceed their costs under a range of assumptions.

As explained in the RIA and further below, the EPA has been 

notified of few power sector NSPS modifications or 

reconstructions. Based on that experience, the EPA expects that 

few EGUs will trigger either the modification or the 

 

17 The EPA’s Integrated Planning Model (IPM) projects no new noncompliant coal (i.e., newly constructed coal-fired plants that 

do not meet the final standard of performance) throughout the 

model horizon of 2030 (there is a small amount of new coal with 

CCS that is hardwired into the modelling, consistent with EIA 

assumptions to represent units already under construction or 

under development).

18 Conditions in the analysis year of 2022 are represented by a 

model year of 2020.
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reconstruction provisions that we are finalizing in this action. 

In Chapter 6 of the RIA, we discuss factors that limit our 

ability to quantify the costs and benefits of the standards for 

modified and reconstructed sources.

B. Does this action apply to me?

The entities potentially affected by the standards are 

shown in Table 2 below.

Table 2. Potentially Affected Entitiesa

Category NAICS 

Code

Examples of Potentially Affected 

Entities

Industry 221112 Fossil fuel electric power generating 

units.

Federal 

Government

221112b Fossil fuel electric power generating 

units owned by the federal government.

State/Local 

Government

221112b Fossil fuel electric power generating 

units owned by municipalities.

Tribal 

Government

921150

Fossil fuel electric power generating 

units in Indian Country.

a Includes NAICS categories for source categories that own and 

operate electric power generating units (including boilers and 

stationary combined cycle combustion turbines).

b Federal, state, or local government-owned and operated 

establishments are classified according to the activity in which 

they are engaged.

This table is not intended to be exhaustive, but rather to 

provide a guide for readers regarding entities likely to be 
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affected by this action. To determine whether your facility, 

company, business, organization, etc., would be regulated by 

this action, refer to Section III of this preamble for more 

information and examine the applicability criteria in 40 CFR 

60.1 (General Provisions) and 40 CFR 60.550840 of subpart TTTT 

(Standards of Performance for Greenhouse Gas Emissions for 

Electric Utility Generating Units). If you have any questions 

regarding the applicability of this action to a particular 

entity, consult either the air permitting authority for the 

entity or your EPA regional representative as listed in 40 CFR 

60.4 or 40 CFR 63.13 (General Provisions).

C. Where can I get a copy of this document?

 In addition to being available in the docket, an electronic 

copy of this final action will also be available on the 

Worldwide Web (WWW). Following signature, a copy of this final 

action will be posted at the following address: 

http://www2.epa.gov/carbon-pollution-standards.

D. Judicial Review

 Under section 307(b)(1) of the CAA, judicial review of this 

final rule is available only by filing a petition for review in 

the U.S. Court of Appeals for the District of Columbia Circuit 

by [insert date 60 days after publication in the Federal 

Register]. Moreover, under section 307(b)(2) of the CAA, the 

requirements established by this final rule may not be 
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challenged separately in any civil or criminal proceedings 

brought by the EPA to enforce these requirements. Section 

307(d)(7)(B) of the CAA further provides that “[o]nly an 

objection to a rule or procedure which was raised with 

reasonable specificity during the period for public comment 

(including any public hearing) may be raised during judicial 

review.” This section also provides a mechanism mandating the 

EPA to convene a proceeding for reconsideration “[i]f the person 

raising an objection can demonstrate to the EPA that it was 

impracticable to raise such objection within [the period for 

public comment] or if the grounds for such objection arose after 

the period for public comment (but within the time specified for 

judicial review) and if such objection is of central relevance 

to the outcome of the rule.” Any person seeking to make such a 

demonstration should submit a Petition for Reconsideration to 

the Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios 

Building, 1200 Pennsylvania Ave., NW., Washington, DC 20460, 

with a copy to both the person(s) listed in the preceding FOR 

FURTHER INFORMATION CONTACT section, and the Associate General 

Counsel for the Air and Radiation Law Office, Office of General 

Counsel (Mail Code 2344A), U.S. EPA, 1200 Pennsylvania Ave., NW, 

Washington, DC 20460.
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E. How is this preamble organized?

This action presents the EPA’s final standards of 

performance for newly constructed, modified, and reconstructed 

fossil fuel-fired electric utility steam generating units and 

newly constructed and reconstructed stationary combustion 

turbines. Section II provides background information on climate 

change impacts from GHG emissions, GHG emissions from fossil 

fuel-fired EGUs, the utility power sector, the statutory and 

regulatory background relating to CAA section 111(b), EPA 

actions prior to this final action, and public comments 

regarding the proposed actions. Section III explains the EPA’s

authority to regulate CO2 and EGUs, identifies affected EGUs, and 

describes the source categories. Section IV provides a summary 

of the final standards for newly constructed, modified, and 

reconstructed fossil fuel-fired steam generating units. Sections 

V through VII present the rationale for the final standards for 

newly constructed, modified, and reconstructed steam generating 

units, respectively. Sections VIII and IX provide a summary of 

the final standards for stationary combustion turbines and 

present the rationale for the final standards for newly 

constructed and reconstructed combustion turbines, respectively. 

Section X provides a summary of other final requirements for 

newly constructed, modified, and reconstructed fossil fuel-fired 

steam generating units and stationary combustion turbines. 
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Section XI addresses the consistency of the respective BSER 

determinations in these rules and under the emission guidelines 

issued separately under CAA section 111(d). Interactions with 

other EPA programs and rules are described in Section XII. 

Projected impacts of the final action are then described in 

Section XIII, followed by a discussion of statutory and 

executive order reviews in Section XIV. Section XV addresses the 

withdrawal of the proposed standards for steam generating EGUs

that make modifications resulting in an increase of hourly CO2

emissions of less than or equal to 10 percent and the proposed 

standards for modified stationary combustion turbines. The

statutory authority for this action is provided in Section XVI.

We address major comments throughout this preamble and in 

greater detail in an accompanying response-to-comments document

located in the docket.

II. Background

In this section, we discuss climate change impacts from GHG 

emissions, both on public health and public welfare. We also 

present information about GHG emissions from fossil fuel-fired 

EGUs and describe the utility power sector and its changing 

structure. We then summarize the statutory and regulatory 

background relevant to this final rulemaking. In addition, we 

provide background information on the EPA’s January 8, 2014 

proposed carbon pollution standards for newly constructed fossil 
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fuel-fired EGUs, the June 18, 2014 proposed carbon pollution 

standards for modified and reconstructed EGUs, and other actions 

associated with this final rulemaking. We close this section

with a general discussion of comments and stakeholder input that 

the EPA received prior to issuing this final rulemaking.

A. Climate Change Impacts from GHG Emissions

According to the National Research Council, “Emissions of 

CO2 from the burning of fossil fuels have ushered in a new epoch 

where human activities will largely determine the evolution of 

Earth’s climate. Because CO2 in the atmosphere is long lived, it 

can effectively lock Earth and future generations into a range 

of impacts, some of which could become very severe. Therefore, 

emission reduction choices made today matter in determining 

impacts experienced not just over the next few decades, but in 

the coming centuries and millennia.”19

In 2009, based on a large body of robust and compelling 

scientific evidence, the EPA Administrator issued the 

Endangerment Finding under CAA section 202(a)(1).20 In the 

Endangerment Finding, the Administrator found that the current, 

elevated concentrations of GHGs in the atmosphere — already at 

 

19 National Research Council, Climate Stabilization Targets, p.

3. 

20 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases Under Section 202(a) of the Clean Air Act,” 74 FR 66496

(Dec. 15, 2009) (“Endangerment Finding”).
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levels unprecedented in human history — may reasonably be 

anticipated to endanger public health and welfare of current and 

future generations in the United States. We summarize these 

adverse effects on public health and welfare briefly here. 

1. Public Health Impacts Detailed in the 2009 Endangerment 

Finding

Climate change caused by human emissions of GHGs threatens 

the health of Americans in multiple ways. By raising average 

temperatures, climate change increases the likelihood of heat 

waves, which are associated with increased deaths and illnesses. 

While climate change also increases the likelihood of reductions 

in cold-related mortality, evidence indicates that the increases 

in heat mortality will be larger than the decreases in cold 

mortality in the United States. Compared to a future without 

climate change, climate change is expected to increase ozone 

pollution over broad areas of the U.S., especially on the 

highest ozone days and in the largest metropolitan areas with 

the worst ozone problems, and thereby increase the risk of 

morbidity and mortality. Climate change is also expected to 

cause more intense hurricanes and more frequent and intense 

storms and heavy precipitation, with impacts on other areas of 

public health, such as the potential for increased deaths, 

injuries, infectious and waterborne diseases, and stress-related 
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disorders. Children, the elderly, and the poor are among the 

most vulnerable to these climate-related health effects.

2. Public Welfare Impacts Detailed in the 2009 Endangerment 

Finding

Climate change impacts touch nearly every aspect of public 

welfare. Among the multiple threats caused by human emissions of 

GHGs, climate changes are expected to place large areas of the 

country at serious risk of reduced water supplies, increased 

water pollution, and increased occurrence of extreme events such 

as floods and droughts. Coastal areas are expected to face a 

multitude of increased risks, particularly from rising sea level 

and increases in the severity of storms. These communities face 

storm and flood damage to property, or even loss of land due to 

inundation, erosion, wetland submergence and habitat loss. 

Impacts of climate change on public welfare also include 

threats to social and ecosystem services. Climate change is 

expected to result in an increase in peak electricity demand. 

Extreme weather from climate change threatens energy, 

transportation, and water resource infrastructure. Climate 

change may also exacerbate ongoing environmental pressures in 

certain settlements, particularly in Alaskan indigenous 

communities, and is very likely to fundamentally rearrange U.S. 

ecosystems over the 21st century. Though some benefits may 

balance adverse effects on agriculture and forestry in the next 
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few decades, the body of evidence points towards increasing 

risks of net adverse impacts on U.S. food production, 

agriculture and forest productivity as temperature continues to 

rise. These impacts are global and may exacerbate problems 

outside the U.S. that raise humanitarian, trade, and national 

security issues for the U.S.

3. New Scientific Assessments and Observations

Since the administrative record concerning the Endangerment 

Finding closed following the EPA’s 2010 Reconsideration Denial, 

the climate has continued to change, with new records being set 

for a number of climate indicators such as global average 

surface temperatures, Arctic sea ice retreat, CO2 concentrations, 

and sea level rise. Additionally, a number of major scientific 

assessments have been released that improve understanding of the 

climate system and strengthen the case that GHGs endanger public 

health and welfare both for current and future generations. 

These assessments, from the Intergovernmental Panel on Climate 

Change (IPCC), the U.S. Global Change Research Program (USGCRP), 

and the National Research Council (NRC), include: IPCC’s 2012 

Special Report on Managing the Risks of Extreme Events and 

Disasters to Advance Climate Change Adaptation (SREX) and the 

2013-2014 Fifth Assessment Report (AR5), the USGCRP’s 2014 

National Climate Assessment, Climate Change Impacts in the 

United States (NCA3), and the NRC’s 2010 Ocean Acidification: A 
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Page 39 of 764

National Strategy to Meet the Challenges of a Changing Ocean

(Ocean Acidification), 2011 Report on Climate Stabilization 

Targets: Emissions, Concentrations, and Impacts over Decades to 

Millennia (Climate Stabilization Targets), 2011 National 

Security Implications for U.S. Naval Forces (National Security 

Implications), 2011 Understanding Earth’s Deep Past: Lessons for 

Our Climate Future (Understanding Earth’s Deep Past), 2012 Sea 

Level Rise for the Coasts of California, Oregon, and Washington: 

Past, Present, and Future, 2012 Climate and Social Stress: 

Implications for Security Analysis (Climate and Social Stress), 

and 2013 Abrupt Impacts of Climate Change (Abrupt Impacts) 

assessments. 

The EPA has carefully reviewed these recent assessments in 

keeping with the same approach outlined in Section III.A of the 

2009 Endangerment Finding, which was to rely primarily upon the 

major assessments by the USGCRP, the IPCC, and the NRC of the 

National Academies to provide the technical and scientific 

information to inform the Administrator’s judgment regarding the 

question of whether GHGs endanger public health and welfare. 

These assessments addressed the scientific issues that the EPA 

was required to examine, were comprehensive in their coverage of 

the GHG and climate change issues, and underwent rigorous and 

exacting peer review by the expert community, as well as 

rigorous levels of U.S. government review. 
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The findings of the recent scientific assessments confirm 

and strengthen the conclusion that GHGs endanger public health, 

now and in the future. The NCA3 indicates that human health in 

the United States will be impacted by “increased extreme weather 

events, wildfire, decreased air quality, threats to mental 

health, and illnesses transmitted by food, water, and diseasecarriers such as mosquitoes and ticks.” The most recent 

assessments now have greater confidence that climate change will 

influence production of pollen that exacerbates asthma and other 

allergic respiratory diseases such as allergic rhinitis, as well 

as effects on conjunctivitis and dermatitis. Both the NCA3 and 

the IPCC AR5 found that increasing temperature has lengthened 

the allergenic pollen season for ragweed, and that increased CO2

by itself can elevate production of plant-based allergens. 

The NCA3 also finds that climate change, in addition to 

chronic stresses such as extreme poverty, is negatively 

affecting indigenous peoples’ health in the United States 

through impacts such as reduced access to traditional foods, 

decreased water quality, and increasing exposure to health and 

safety hazards. The IPCC AR5 finds that climate change-induced 

warming in the Arctic and resultant changes in environment 

(e.g., permafrost thaw, effects on traditional food sources) 

have significant impacts, observed now and projected, on the 

health and well-being of Arctic residents, especially indigenous 
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peoples. Small, remote, predominantly-indigenous communities are 

especially vulnerable given their “strong dependence on the 

environment for food, culture, and way of life; their political 

and economic marginalization; existing social, health, and 

poverty disparities; as well as their frequent close proximity 

to exposed locations along ocean, lake, or river shorelines.”21 

In addition, increasing temperatures and loss of Arctic sea ice 

increases the risk of drowning for those engaged in traditional 

hunting and fishing.

The NCA3 concludes that children’s unique physiology and 

developing bodies contribute to making them particularly 

vulnerable to climate change. Impacts on children are expected 

from heat waves, air pollution, infectious and waterborne 

illnesses, and mental health effects resulting from extreme 

weather events. The IPCC AR5 indicates that children are among 

those especially susceptible to most allergic diseases, as well 

as health effects associated with heat waves, storms, and 

floods. The IPCC finds that additional health concerns may arise 

in low-income households, especially those with children, if 

 

21 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 

Vulnerability. Part B: Regional Aspects. Contribution of Working 

Group II to the Fifth Assessment Report of the Intergovernmental 

Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, 

M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. 

Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 

Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 

Cambridge University Press, Cambridge, p. 1581.
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climate change reduces food availability and increases prices, 

leading to food insecurity within households.

Both the NCA3 and IPCC AR5 conclude that climate change 

will increase health risks facing the elderly. Older people are 

at much higher risk of mortality during extreme heat events. 

Pre-existing health conditions also make older adults 

susceptible to cardiac and respiratory impacts of air pollution 

and to more severe consequences from infectious and waterborne 

diseases. Limited mobility among older adults can also increase 

health risks associated with extreme weather and floods.

The new assessments also confirm and strengthen the 

conclusion that GHGs endanger public welfare, and emphasize the 

urgency of reducing GHG emissions due to their projections that 

show GHG concentrations climbing to ever-increasing levels in 

the absence of mitigation. The NRC assessment, Understanding 

Earth’s Deep Past, projected that, without a reduction in 

emissions, CO2 concentrations by the end of the century would 

increase to levels that the Earth has not experienced for more 

than 30 million years.22 In fact, that assessment stated that 

“the magnitude and rate of the present greenhouse gas increase 

place the climate system in what could be one of the most severe 

increases in radiative forcing of the global climate system in 

 

22 National Research Council, Understanding Earth’s Deep Past, p. 

1.
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Earth history.”23 Because of these unprecedented changes, several 

assessments state that we may be approaching critical, poorly 

understood thresholds. As stated in the assessment, “As Earth 

continues to warm, it may be approaching a critical climate 

threshold beyond which rapid and potentially permanent — at 

least on a human timescale — changes not anticipated by climate 

models tuned to modern conditions may occur.” The NRC Abrupt 

Impacts report analyzed abrupt climate change in the physical 

climate system and abrupt impacts of ongoing changes that, when 

thresholds are crossed, can cause abrupt impacts for society and 

ecosystems. The report considered destabilization of the West 

Antarctic Ice Sheet (which could cause 3-4 m of potential sea 

level rise) as an abrupt climate impact with unknown but 

probably low probability of occurring this century. The report 

categorized a decrease in ocean oxygen content (with attendant 

threats to aerobic marine life); increase in intensity, 

frequency, and duration of heat waves; and increase in frequency 

and intensity of extreme precipitation events (droughts, floods, 

hurricanes, and major storms) as climate impacts with moderate 

risk of an abrupt change within this century. The NRC Abrupt 

Impacts report also analyzed the threat of rapid state changes 

in ecosystems and species extinctions as examples of 

 

23 Id., p. 138.
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irreversible impacts that are expected to be exacerbated by 

climate change. Species at most risk include those whose 

migration potential is limited, whether because they live on 

mountaintops or fragmented habitats with barriers to movement, 

or because climatic conditions are changing more rapidly than 

the species can move or adapt. While the NRC determined that it 

is not presently possible to place exact probabilities on the 

added contribution of climate change to extinction, they did 

find that there was substantial risk that impacts from climate 

change could, within a few decades, drop the populations in many 

species below sustainable levels, thereby committing the species 

to extinction. Species within tropical and subtropical 

rainforests such as the Amazon and species living in coral reef 

ecosystems were identified by the NRC as being particularly 

vulnerable to extinction over the next 30 to 80 years, as were 

species in high latitude and high elevation regions. Moreover, 

due to the time lags inherent in the Earth’s climate, the NRC 

Climate Stabilization Targets assessment notes that the full 

warming from any given concentration of CO2 reached will not be 

fully realized for several centuries, underscoring that emission 

activities today carry with them climate commitments far into 

the future.

Future temperature changes will depend on what emission 

path the world follows. In its high emission scenario, the IPCC 
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AR5 projects that average global temperatures by the end of the 

century will likely be 2.6 degrees Celsius (°C) to 4.8 °C (4.7 

to 8.6 degrees Fahrenheit (°F)) warmer than today. Temperatures 

on land and in northern latitudes will likely warm even faster 

than the global average. However, according to the NCA3, 

significant reductions in emissions would lead to noticeably 

less future warming beyond mid-century, and therefore less 

impact to public health and welfare. 

While rainfall may only see small globally and annually 

averaged changes, there are expected to be substantial shifts in 

where and when that precipitation falls. According to the NCA3, 

regions closer to the poles will see more precipitation, while 

the dry subtropics are expected to expand (colloquially, this 

has been summarized as wet areas getting wetter and dry regions 

getting drier). In particular, the NCA3 notes that the western 

U.S., and especially the Southwest, is expected to become drier. 

This projection is consistent with the recent observed drought 

trend in the West. At the time of publication of the NCA, even 

before the last 2 years of extreme drought in California, tree 

ring data was already indicating that the region might be 

experiencing its driest period in 800 years. Similarly, the NCA3 

projects that heavy downpours are expected to increase in many 

regions, with precipitation events in general becoming less 

frequent but more intense. This trend has already been observed 
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in regions such as the Midwest, Northeast, and upper Great 

Plains. Meanwhile, the NRC Climate Stabilization Targets 

assessment found that the area burned by wildfire is expected to 

grow by 2 to 4 times for 1 °C (1.8 °F) of warming. For 3 °C of 

warming, the assessment found that 9 out of 10 summers would be 

warmer than all but the 5 percent of warmest summers today, 

leading to increased frequency, duration, and intensity of heat 

waves. Extrapolations by the NCA also indicate that Arctic sea 

ice in summer may essentially disappear by mid-century. 

Retreating snow and ice, and emissions of CO2 and methane 

released from thawing permafrost, will also amplify future 

warming. 

Since the 2009 Endangerment Finding, the USGCRP NCA3, and 

multiple NRC assessments have projected future rates of sea 

level rise that are 40 percent larger to more than twice as 

large as the previous estimates from the 2007 IPCC 4th Assessment 

Report due in part to improved understanding of the future rate 

of melt of the Antarctic and Greenland Ice sheets. The NRC Sea 

Level Rise assessment projects a global sea level rise of 0.5 to 

1.4 meters (1.6 to 4.6 feet) by 2100, the NRC National Security 

Implications assessment suggests that “the Department of the 

Navy should expect roughly 0.4 to 2 meters (1.3 to 6.6 feet)
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global average sea-level rise by 2100,”24 and the NRC Climate 

Stabilization Targets assessment states that an increase of 3 °C 

will lead to a sea level rise of 0.5 to 1 meter (1.6 to 3.3 

feet) by 2100. These assessments continue to recognize that 

there is uncertainty inherent in accounting for ice sheet 

processes. Additionally, local sea level rise can differ from 

the global total depending on various factors. The east coast of 

the U.S. in particular is expected to see higher rates of sea 

level rise than the global average. For comparison, the NCA3 

states that “five million Americans and hundreds of billions of 

dollars of property are located in areas that are less than four 

feet above the local high-tide level,” and the NCA3 finds that 

“[c]oastal infrastructure, including roads, rail lines, energy 

infrastructure, airports, port facilities, and military bases, 

are increasingly at risk from sea level rise and damaging storm 

surges.”25 Also, because of the inertia of the oceans, sea level 

rise will continue for centuries after GHG concentrations have 

stabilized (though more slowly than it would have otherwise). 

Additionally, there is a threshold temperature above which the 

Greenland ice sheet will be committed to inevitable melting.

 

24 NRC, 2011: National Security Implications of Climate Change 

for U.S. Naval Forces. The National Academies Press, p. 28.

25 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, 

Eds., 2014: Climate Change Impacts in the United States: The 

Third National Climate Assessment. U.S. Global Change Research 

Program, p. 9.
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According to the NCA, some recent research has suggested that 

even present day CO2 levels could be sufficient to exceed that 

threshold.

In general, climate change impacts are expected to be 

unevenly distributed across different regions of the United 

States and have a greater impact on certain populations, such as 

indigenous peoples and the poor. The NCA3 finds that climate 

change impacts such as the rapid pace of temperature rise, 

coastal erosion and inundation related to sea level rise and 

storms, ice and snow melt, and permafrost thaw are affecting 

indigenous people in the U.S. Particularly in Alaska, critical 

infrastructure and traditional livelihoods are threatened by 

climate change and, “[i]n parts of Alaska, Louisiana, the 

Pacific Islands, and other coastal locations, climate change 

impacts (through erosion and inundation) are so severe that some 

communities are already relocating from historical homelands to 

which their traditions and cultural identities are tied.”26 The 

IPCC AR5 notes, “Climate-related hazards exacerbate other 

stressors, often with negative outcomes for livelihoods, 

especially for people living in poverty (high confidence). 

Climate-related hazards affect poor people’s lives directly 

 

26 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, 

Eds., 2014: Climate Change Impacts in the United States: The 

Third National Climate Assessment. U.S. Global Change Research 

Program, p. 17.
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through impacts on livelihoods, reductions in crop yields, or 

destruction of homes and indirectly through, for example, 

increased food prices and food insecurity.”27

CO2 in particular has unique impacts on ocean ecosystems. 

The NRC Climate Stabilization Targets assessment found that 

coral bleaching will increase due both to warming and ocean 

acidification. Ocean surface waters have already become 30

percent more acidic over the past 250 years due to absorption of 

CO2 from the atmosphere. According to the NCA3, this 

acidification will reduce the ability of organisms such as 

corals, krill, oysters, clams, and crabs to survive, grow, and 

reproduce. The NRC Understanding Earth's Deep Past assessment 

notes that four of the five major coral reef crises of the past 

500 million years were caused by acidification and warming that 

followed GHG increases of similar magnitude to the emissions 

increases expected over the next hundred years. The NRC Abrupt 

Impacts assessment specifically highlighted similarities between 

the projections for future acidification and warming and the 

extinction at the end of the Permian which resulted in the loss 

 

27 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 

Vulnerability. Part A: Global and Sectoral Aspects. Contribution 

of Working Group II to the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change [Field, C.B., V.R. 

Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. 

Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. 

Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, p. 796.
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of an estimated 90 percent of known species. Similarly, the NRC 

Ocean Acidification assessment finds that “[t]he chemistry of 

the ocean is changing at an unprecedented rate and magnitude due 

to anthropogenic CO2 emissions; the rate of change exceeds any 

known to have occurred for at least the past hundreds of 

thousands of years.”28 The assessment notes that the full range 

of consequences is still unknown, but the risks “threaten coral 

reefs, fisheries, protected species, and other natural resources 

of value to society.”29 

Events outside the United States, as also pointed out in 

the 2009 Endangerment Finding, will also have relevant 

consequences. The NRC Climate and Social Stress assessment 

concluded that it is prudent to expect that some climate events 

“will produce consequences that exceed the capacity of the 

affected societies or global systems to manage and that have 

global security implications serious enough to compel 

international response.” The NRC National Security Implications 

assessment recommends preparing for increased needs for 

humanitarian aid; responding to the effects of climate change in 

geopolitical hotspots, including possible mass migrations; and 

 

28 NRC, 2010: Ocean Acidification: A National Strategy to Meet 

the Challenges of a Changing Ocean. The National Academies 

Press, p. 5.

29 Id.
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addressing changing security needs in the Arctic as sea ice 

retreats.

In addition to future impacts, the NCA3 emphasizes that 

climate change driven by human emissions of GHGs is already 

happening now and it is happening in the United States. 

According to the IPCC AR5 and the NCA3, there are a number of 

climate-related changes that have been observed recently, and 

these changes are projected to accelerate in the future. The 

planet warmed about 0.85 °C (1.5 °F) from 1880 to 2012. It is 

extremely likely (>95 percent probability) that human influence 

was the dominant cause of the observed warming since the mid-20th

century, and likely (>66 percent probability) that human 

influence has more than doubled the probability of occurrence of 

heat waves in some locations. In the Northern Hemisphere, the 

last 30 years were likely the warmest 30-year period of the last 

1400 years. U.S. average temperatures have similarly increased 

by 1.3 to 1.9 °F since 1895, with most of that increase 

occurring since 1970. Global sea levels rose 0.19 m (7.5 inches) 

from 1901 to 2010. Contributing to this rise was the warming of 

the oceans and melting of land ice. It is likely that 275 

gigatons per year of ice have melted from land glaciers (not 

including ice sheets) since 1993, and that the rate of loss of 

ice from the Greenland and Antarctic ice sheets has increased 

substantially in recent years, to 215 gigatons per year and 147 
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gigatons per year respectively, since 2002. For context, 360 

gigatons of ice melt is sufficient to cause global sea levels to 

rise 1 mm. Annual mean Arctic sea ice has been declining at 3.5 

to 4.1 percent per decade, and Northern Hemisphere snow cover 

extent has decreased at about 1.6 percent per decade for March 

and 11.7 percent per decade for June. Permafrost temperatures 

have increased in most regions since the 1980s, by up to 3 °C 

(5.4 °F) in parts of Northern Alaska. Winter storm frequency and 

intensity have both increased in the Northern Hemisphere. The 

NCA3 states that the increases in the severity or frequency of 

some types of extreme weather and climate events in recent 

decades can affect energy production and delivery, causing 

supply disruptions, and compromise other essential 

infrastructure such as water and transportation systems. 

In addition to the changes documented in the assessment 

literature, there have been other climate milestones of note. In 

2009, the year of the Endangerment Finding, the average 

concentration of CO2 as measured on top of Mauna Loa was 387 

parts per million, far above preindustrial concentrations of 

about 280 parts per million.31 The average concentration in 2013, 

the last full year before this rule was proposed, was 396 parts 

per million. The average concentration in 2014 was 399 parts per 

 

31

ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.txt
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million. And the monthly concentration in April of 2014 was 401 

parts per million, the first time a monthly average has exceeded 

400 parts per million since record keeping began at Mauna Loa in 

1958, and for at least the past 800,000 years based on ice core 

records.

33 Arctic sea ice has continued to decline, with 

September of 2012 marking a new record low in terms of Arctic 

sea ice extent, 40 percent below the 1979-2000 median. Sea level 

has continued to rise at a rate of 3.2 mm per year (1.3 

inches/decade) since satellite observations started in 1993, 

more than twice the average rate of rise in the 20th century 

prior to 1993.34 And 2014 was the warmest year globally in the 

modern global surface temperature record, going back to 1880; 

this now means 19 of the 20 warmest years have occurred in the 

past 20 years, and except for 1998, the ten warmest years on 

record have occurred since 2002.35 The first months of 2015 have 

also been some of the warmest on record. 

These assessments and observed changes make it clear that 

reducing emissions of GHGs across the globe is necessary in 

order to avoid the worst impacts of climate change, and 

underscore the urgency of reducing emissions now. The NRC 

Committee on America’s Climate Choices listed a number of 

 

33 http://www.esrl.noaa.gov/gmd/ccgg/trends/.

34 Blunden, J., and D. S. Arndt, Eds., 2014: State of the Climate 

in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1-S238.

35 http://www.ncdc.noaa.gov/sotc/global/2014/13.
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reasons “why it is imprudent to delay actions that at least 

begin the process of substantially reducing emissions.”36 For 

example:

 The faster emissions are reduced, the lower the risks 

posed by climate change. Delays in reducing emissions 

could commit the planet to a wide range of adverse 

impacts, especially if the sensitivity of the climate to 

greenhouse gases is on the higher end of the estimated 

range.

 Waiting for unacceptable impacts to occur before taking 

action is imprudent because the effects of greenhouse gas 

emissions do not fully manifest themselves for decades 

and, once manifest, many of these changes will persist 

for hundreds or even thousands of years.

 In the committee’s judgment, the risks associated with 

doing business as usual are a much greater concern than 

the risks associated with engaging in strong response 

efforts.

4. Observed and Projected U.S. Regional Changes

The NCA3 assessed the climate impacts in eight regions of 

the United States, noting that changes in physical climate 

parameters such as temperatures, precipitation, and sea ice 

retreat were already having impacts on forests, water supplies, 

ecosystems, flooding, heat waves, and air quality. Moreover, the 

NCA3 found that future warming is projected to be much larger 

than recent observed variations in temperature, with 

precipitation likely to increase in the northern states, 

 

36 NRC, 2011: America’s Climate Choices, The National Academies 

Press.
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decrease in the southern states, and with the heaviest 

precipitation events projected to increase everywhere. 

In the Northeast, temperatures increased almost 2 °F from 

1895 to 2011, precipitation increased by about 5 inches (10

percent), and sea level rise of about a foot has led to an 

increase in coastal flooding. The 70 percent increase in the 

amount of rainfall falling in the 1 percent of the most intense 

events is a larger increase in extreme precipitation than 

experienced in any other U.S. region. 

In the future, if emissions continue increasing, the 

Northeast is expected to experience 4.5 to 10 °F of warming by 

the 2080s. This will lead to more heat waves, coastal and river 

flooding, and intense precipitation events. The southern portion 

of the region is projected to see 60 additional days per year 

above 90 °F by mid-century. Sea levels in the Northeast are 

expected to increase faster than the global average because of 

subsidence, and changing ocean currents may further increase the 

rate of sea level rise. Specific vulnerabilities highlighted by 

the NCA include large urban populations particularly vulnerable 

to climate-related heat waves and poor air quality episodes, 

prevalence of climate sensitive vector-borne diseases like Lyme 

and West Nile Virus, usage of combined sewer systems that may 

lead to untreated water being released into local water bodies 

after climate-related heavy precipitation events, and 1.6 
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million people living within the 100-year coastal flood zone who 

are expected to experience more frequent floods due to sea level 

rise and tropical-storm induced storm-surge. The NCA also 

highlighted infrastructure vulnerable to inundation in coastal 

metropolitan areas, potential agricultural impacts from 

increased rain in the spring delaying planting or damaging crops 

or increased heat in the summer leading to decreased yields and 

increased water demand, and shifts in ecosystems leading to 

declines in iconic species in some regions, such as cod and 

lobster south of Cape Cod. 

In the Southeast, average annual temperature during the 

last century cycled between warm and cool periods. A warm peak 

occurred during the 1930s and 1940s, followed by a cool period,

and temperatures then increased again from 1970 to the present 

by an average of 2 °F. There have been increasing numbers of 

days above 95 °F and nights above 75 °F, and decreasing numbers 

of extremely cold days since 1970. Daily and five-day rainfall 

intensities have also increased, and summers have been either 

increasingly dry or extremely wet. Louisiana has already lost 

1,880 square miles of land in the last 80 years due to sea level 

rise and other contributing factors.

The Southeast is exceptionally vulnerable to sea level 

rise, extreme heat events, hurricanes, and decreased water 

availability. Major consequences of further warming include 
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significant increases in the number of hot days (95 °F or above) 

and decreases in freezing events, as well as exacerbated groundlevel ozone in urban areas. Although projected warming for some 

parts of the region by the year 2100 is generally smaller than 

for other regions of the United States, projected warming for 

interior states of the region is larger than coastal regions by 

1 °F to 2 °F. Projections further suggest that there will be 

fewer tropical storms globally, but that they will be more 

intense, with more Category 4 and 5 storms. The NCA identified 

New Orleans, Miami, Tampa, Charleston, and Virginia Beach as 

being specific cities that are at risk due to sea level rise, 

with homes and infrastructure increasingly prone to flooding. 

Additional impacts of sea level rise are expected for coastal 

highways, wetlands, fresh water supplies, and energy 

infrastructure.

In the Northwest, temperatures increased by about 1.3

oF

between 1895 and 2011. A small average increase in precipitation 

was observed over this time period. However, warming 

temperatures have caused increased rainfall relative to 

snowfall, which has altered water availability from snowpack 

across parts of the region. Snowpack in the Northwest is an 

important freshwater source for the region. More precipitation 

falling as rain instead of snow has reduced the snowpack, and 

warmer springs have corresponded to earlier snowpack melting and 
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reduced streamflows during summer months. Drier conditions have 

increased the extent of wildfires in the region.

Average annual temperatures are projected to increase by 

3.3

oF to 9.7oF by the end of the century (depending on future 

global GHG emissions), with the greatest warming expected during 

the summer. Continued increases in global GHG emissions are 

projected to result in up to a 30 percent decrease in summer 

precipitation. Earlier snowpack melt and lower summer stream

flows are expected by the end of the century and will affect 

drinking water supplies, agriculture, ecosystems, and hydropower 

production. Warmer waters are expected to increase disease and 

mortality in important fish species, including Chinook and 

sockeye salmon. Ocean acidification also threatens species such 

as oysters, with the Northwest coastal waters already being some 

of the most acidified worldwide due to coastal upwelling and 

other local factors. Forest pests are expected to spread and 

wildfires to burn larger areas. Other high-elevation ecosystems 

are projected to be lost because they can no longer survive the 

climatic conditions. Low lying coastal areas, including the 

cities of Seattle and Olympia, will experience heightened risks 

of sea level rise, erosion, seawater inundation and damage to 

infrastructure and coastal ecosystems.

In Alaska, temperatures have changed faster than anywhere

else in the United States. Annual temperatures increased by 
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about 3 °F in the past 60 years. Warming in the winter has been 

even greater, rising by an average of 6 °F. Arctic sea ice is 

thinning and shrinking in area, with the summer minimum ice 

extent now covering only half the area it did when satellite 

records began in 1979. Glaciers in Alaska are melting at some of 

the fastest rates on Earth. Permafrost soils are also warming 

and beginning to thaw. Drier conditions have contributed to more 

large wildfires in the last 10 years than in any previous decade 

since the 1940s, when recordkeeping began. Climate change 

impacts are harming the health, safety, and livelihoods of 

Native Alaskan communities. 

By the end of this century, continued increases in GHG

emissions are expected to increase temperatures by 10 to 12 °F 

in the northernmost parts of Alaska, by 8 to 10 °F in the 

interior, and by 6 to 8 °F across the rest of the state. These 

increases will exacerbate ongoing arctic sea ice loss, glacial 

melt, permafrost thaw and increased wildfire, and threaten 

humans, ecosystems, and infrastructure. Precipitation is 

expected to increase to varying degrees across the state.

However, warmer air temperatures and a longer growing season are 

expected to result in drier conditions. Native Alaskans are 

expected to experience declines in economically, nutritionally, 

and culturally important wildlife and plant species. Health 

threats will also increase, including loss of clean water, 
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saltwater intrusion, sewage contamination from thawing 

permafrost, and northward extension of diseases. Wildfires will 

increasingly pose threats to human health as a result of smoke 

and direct contact. Areas underlain by ice-rich permafrost 

across the state are likely to experience ground subsidence and 

extensive damage to infrastructure as the permafrost thaws. 

Important ecosystems will continue to be affected. Surface 

waters and wetlands that are drying provide breeding habitat for 

millions of waterfowl and shorebirds that winter in the lower 48 

states. Warmer ocean temperatures, acidification, and declining 

sea ice will contribute to changes in the location and 

availability of commercially and culturally important marine 

fish.

In the Southwest, temperatures are now about 2 °F higher

than the past century, and are already the warmest that region 

has experienced in at least 600 years. The NCA notes that there 

is evidence that climate change-induced warming on top of recent 

drought has influenced tree mortality, wildfire frequency and 

area, and forest insect outbreaks. Sea levels have risen about 7 

or 8 inches in this region, contributing to inundation of 

Highway 101 and backup of seawater into sewage systems in the 

San Francisco area. 

Projections indicate that the Southwest will warm an 

additional 5.5 to 9.5 °F over the next century if emissions 
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continue to increase. Winter snowpack in the Southwest is 

projected to decline (consistent with the record lows from this 

past winter), reducing the reliability of surface water supplies 

for cities, agriculture, cooling for power plants, and 

ecosystems. Sea level rise along the California coast will 

worsen coastal erosion, increase flooding risk for coastal 

highways, bridges, and low-lying airports, pose a threat to 

groundwater supplies in coastal cities such as Los Angeles, and 

increase vulnerability to floods for hundreds of thousands of 

residents in coastal areas. Climate change will also have 

impacts on the high-value specialty crops grown in the region as 

a drier climate will increase demands for irrigation, more 

frequent heat waves will reduce yields, and decreased winter 

chills may impair fruit and nut production for trees in 

California. Increased drought, higher temperatures, and bark 

beetle outbreaks are likely to contribute to continued increases 

in wildfires. The highly urbanized population of the Southwest 

is vulnerable to heat waves and water supply disruptions, which 

can be exacerbated in cases where high use of air conditioning 

triggers energy system failures. 

The rate of warming in the Midwest has markedly accelerated 

over the past few decades. Temperatures rose by more than 1.5 °F 

from 1900 to 2010, but between 1980 and 2010, the rate of 

warming was three times faster than from 1900 through 2010. 
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Precipitation generally increased over the last century, with 

much of the increase driven by intensification of the heaviest 

rainfalls. Several types of extreme weather events in the 

Midwest (e.g., heat waves and flooding) have already increased 

in frequency and/or intensity due to climate change.

In the future, if emissions continue increasing, the 

Midwest is expected to experience 5.6 to 8.5 °F of warming by 

the 2080s, leading to more heat waves. Though projections of 

changes in total precipitation vary across the regions, more 

precipitation is expected to fall in the form of heavy downpours 

across the entire region, leading to an increase in flooding. 

Specific vulnerabilities highlighted by the NCA include longterm decreases in agricultural productivity, changes in the 

composition of the region’s forests, increased public health 

threats from heat waves and degraded air and water quality, 

negative impacts on transportation and other infrastructure 

associated with extreme rainfall events and flooding, and risks 

to the Great Lakes including shifts in invasive species, 

increases in harmful algal blooms, and declining beach health. 

High temperatures (more than 100 °F in the Southern Plains

and more than 95 °F in the Northern Plains) are projected to 

occur much more frequently by mid-century. Increases in extreme 

heat will increase heat stress for residents, energy demand for 

air conditioning, and water losses. North Dakota’s increase in 
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annual temperatures over the past 130 years is the fastest in 

the contiguous U.S., mainly driven by warming winters. Specific 

vulnerabilities highlighted by the NCA include increased demand 

for water and energy, changes to crop-growth cycles and 

agricultural practices, and negative impacts on local plant and 

animal species from habitat fragmentation, wildfires, and 

changes in the timing of flowering or pest patterns. Communities 

that are already the most vulnerable to weather and climate 

extremes will be stressed even further by more frequent extreme 

events occurring within an already highly variable climate 

system. 

In Hawaii, other Pacific islands, and the Caribbean, rising 

air and ocean temperatures, shifting rainfall patterns, changing 

frequencies and intensities of storms and drought, decreasing 

baseflow in streams, rising sea levels, and changing ocean 

chemistry will affect ecosystems on land and in the oceans, as 

well as local communities, livelihoods, and cultures. Low 

islands are particularly at risk.

Rising sea levels, coupled with high water levels caused by 

tropical and extra-tropical storms, will incrementally increase 

coastal flooding and erosion, damaging coastal ecosystems, 

infrastructure, and agriculture, and negatively affecting 

tourism. Ocean temperatures in the Pacific region exhibit strong 

year-to-year and decadal fluctuations, but since the 1950s, they 
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have exhibited a warming trend, with temperatures from the 

surface to a depth of 660 feet rising by as much as 3.6 °F. As a 

result of current sea level rise, the coastline of Puerto Rico 

around Rincón is being eroded at a rate of 3.3 feet per year. 

Freshwater supplies are already constrained and will become more 

limited on many islands. Saltwater intrusion associated with sea 

level rise will reduce the quantity and quality of freshwater in 

coastal aquifers, especially on low islands. In areas where 

precipitation does not increase, freshwater supplies will be 

adversely affected as air temperature rises.

Warmer oceans are leading to increased coral bleaching 

events and disease outbreaks in coral reefs, as well as changed 

distribution patterns of tuna fisheries. Ocean acidification 

will reduce coral growth and health. Warming and acidification, 

combined with existing stresses, will strongly affect coral-reef 

fish communities. For Hawaii and the Pacific islands, future sea 

surface temperatures are projected to increase 2.3 °F by 2055 

and 4.7 °F by 2090 under a scenario that assumes continued 

increases in emissions. Ocean acidification is also taking place 

in the region, which adds to ecosystem stress from increasing 

temperatures. Ocean acidity has increased by about 30 percent

since the pre-industrial era and is projected to further 

increase by 37 percent to 50 percent from present levels by 

2100. 
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The NCA also discussed impacts that occur along the coasts 

and in the oceans adjacent to many regions, and noted that other 

impacts occur across regions and landscapes in ways that do not 

follow political boundaries.

B. GHG Emissions from Fossil Fuel-fired EGUs

Fossil fuel-fired EGUs are by far the largest emitters of 

GHGs among stationary sources in the U.S., primarily in the form 

of CO2. Among fossil fuel-fired EGUs, coal-fired units are by far 

the largest emitters. This section describes the amounts of 

these emissions and places these amounts in the context of the 

U.S. Inventory of Greenhouse Gas Emissions and Sinks37 (the U.S. 

GHG Inventory). 

The EPA implements a separate program under 40 CFR part 98 

called the Greenhouse Gas Reporting Program38 (GHGRP) that 

requires emitting facilities that emit over certain threshold 

amounts of GHGs to report their emissions to the EPA annually. 

Using data from the GHGRP, this section also places emissions 

from fossil fuel-fired EGUs in the context of the total 

 

37 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 –

2013”, Report EPA 430-R-15-004, United States Environmental 

Protection Agency, April 15, 2015.

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

38 U.S. EPA Greenhouse Gas Reporting Program Dataset, see 

http://www.epa.gov/ghgreporting/ghgdata/reportingdatasets.html.
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emissions reported to the GHGRP from facilities in the other 

largest-emitting industries. 

The EPA prepares the official U.S. GHG Inventory to comply 

with commitments under the United Nations Framework Convention 

on Climate Change (UNFCCC). This inventory, which includes 

recent trends, is organized by industrial sector. It provides 

the information in Table 3 below, which presents total U.S. 

anthropogenic emissions and sinks39 of GHGs, including CO2

emissions, for the years 1990, 2005 and 2013.

Table 3. U.S. GHG Emissions and Sinks by Sector (million metric 

tons carbon dioxide equivalent (MMT CO2e))40,41

SECTOR 1990 2005 2013

Energy42

 

5,290.5 

 

6,273.6

 

5,636.6

Industrial Processes 

and Product Use 342.1 367.4 359.1

Agriculture 448.7 494.5 515.7

Land Use, Land-Use 

Change and Forestry

 

13.8 25.5 23.3 

 

39 Sinks are physical units or processes that store GHGs, such as 

forests or underground or deep sea reservoirs of CO2.

40 From Table ES-4 of “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15, 2015.

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html 

41 1 metric ton (tonne) is equivalent to 1,000 kilograms (kg) and 

is equivalent to 1.1023 short tons or 2,204.62 pounds (lb).

42 The energy sector includes all greenhouse gases resulting from 

stationary and mobile energy activities including fuel 

combustion and fugitive fuel emissions.
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Waste 206.0 189.2 138.3

Total Emissions 6,301.1 7,350.2

 

6,673.0

Land Use, Land-Use 

Change and Forestry 

(Sinks)

 

(775.8) (911.9) (881.7)

Net Emissions 

(Sources and Sinks)

 

5,525.2 6,438.3

 

5,791.2

Total fossil energy-related CO2 emissions (including both 

stationary and mobile sources) are the largest contributor to 

total U.S. GHG emissions, representing 77.3 percent of total 

2013 GHG emissions.43 In 2013, fossil fuel combustion by the 

utility power sector – entities that burn fossil fuel and whose 

primary business is the generation of electricity – accounted 

for 38.3 percent of all energy-related CO2 emissions.44 Table 4 

below presents total CO2 emissions from fossil fuel-fired EGUs, 

for years 1990, 2005, and 2013.

Table 4. U.S. GHG Emissions from Generation of Electricity from 

Combustion of Fossil Fuels (MMT CO2)

45

 

43 From Table ES-2 “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15, 2015.

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

.

44 From Table 3-1 “Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15, 2015.

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

45 From Table 3-5 “Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15 2015.
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In addition to preparing the official U.S. GHG Inventory to 

present comprehensive total U.S. GHG emissions and comply with 

commitments under the UNFCCC, the EPA collects detailed GHG 

emissions data from the largest emitting facilities in the U.S. 

through its GHGRP. Data collected by the GHGRP from large 

stationary sources in the industrial sector show that the 

utility power sector emits far greater CO2 emissions than any

other industrial sector. Table 5 below presents total GHG 

emissions in 2013 for the largest emitting industrial sectors as 

reported to the GHGRP. As shown in Table 4 and Table 5, 

respectively, CO2 emissions from fossil fuel-fired EGUs are 

nearly three times as large as the total reported GHG emissions 

from the next ten largest emitting industrial sectors in the 

GHGRP database combined.

 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

.

GHG EMISSIONS 1990 2005 2013

Total CO2 from fossil fuelfired EGUs 

1,820.8 

 

2,400.9 

 

2,039.8 

 - from coal

 

1,547.6 

 

1,983.8

 

1,575.0

 - from natural gas

 

175.3 

 

318.8 441.9 

 - from petroleum

 

97.5 

 

97.9 22.4
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Table 5. Direct GHG Emissions Reported to GHGRP by Largest 

Emitting Industrial Sectors (MMT CO2e)46

It should be noted that the discussion above concerned all 

fossil fuel-fired EGUs. Steam generators emitted 1,627 MMT CO2e

and combustion turbines emitted 401 MMT CO2e in 2013.47

C. The Utility Power Sector

1. Modern Electric System Trends

The EPA includes a background discussion of the electricity 

system in the Clean Power Plan (CPP) rulemaking, which is the 

companion rulemaking to this rule that promulgates emission 

guidelines for states to use in regulating emissions of CO2 from 

existing fossil fuel-fired EGUs. Readers are referred to that 

rulemaking. The following discussion of electricity sector 

 

46 U.S. EPA Greenhouse Gas Reporting Program Dataset as of August 

18, 2014. http://ghgdata.epa.gov/ghgp/main.do.

47 These figures are based on data for EGUs in the Acid Rain 

Program plus additional ones that report to the EPA under the 

Regional Greenhouse Gas Initiative.

Industrial Sector 2013

Fossil Fuel-fired EGUs 2,039.8 

Petroleum Refineries

Onshore Oil & Gas Production

176.7

94.8

Municipal Solid Waste Landfills 93.0

Iron & Steel Production 84.2 

Cement Production 62.8

Natural Gas Processing Plants 59.0

Petrochemical Production 52.7

Hydrogen Production 41.9

Underground Coal Mines 39.8

Food Processing Facilities 30.8
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trends is of particular relevance for this rulemaking.

The electricity sector is undergoing a period of intense 

change. Fossil fuels – such as coal, natural gas, and oil – have 

historically provided a large percentage of electricity in the 

U.S., with smaller amounts being provided by other types of 

generation, including nuclear and renewables such as wind, 

solar, and hydroelectric power. Coal has historically provided 

the largest percentage of fossil-fuel generation.48 In recent 

years, the nation has seen a sizeable increase in renewable 

generation such as wind and solar, as well as a shift from coal 

to natural gas.49 In 2013, fossil fuels supplied 67 percent of 

U.S. electricity, but renewables made up 38 percent of the new 

generation capacity (over 5 GW out of 13.5 GW).50 From 2007 to 

2014, use of lower- and zero-carbon energy sources has grown, 

 

48 U.S. Energy Information Administration, “Table 7.2b 

Electricity Net Generation: Electric Power Sector” data from 

April 2014 Monthly Energy Review, release data April 25, 2014,

available at

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.

49 U.S. Energy Information Administration, “Table 7.2b 

Electricity Net Generation: Electric Power Sector” data from 

April 2014 Monthly Energy Review, release data April 25, 2014, 

available at

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.

50 Based on Table 6.3 (New Utility Scale Generating Units by 

Operating Company, Plant, Month, and Year) of the U.S. Energy 

Information Administration (EIA) Electric Power Monthly, data 

for December 2013, for the following renewable energy sources: 

solar, wind, hydro, geothermal, landfill gas, and biomass. 

Available at: http://

www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_6_0

3.
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while other major energy sources such as coal and oil have 

experienced declines. Renewable electricity generation, 

including from large hydro-electric projects, grew from 8 

percent to 13 percent over that time period.51 Between 2000 and 

2013, approximately 90 percent of new power generation capacity 

built in the U.S. has come in the form of natural gas or 

renewable energy facilities.52 In 2015, the U.S. Energy 

Information Administration (EIA) projected the need for 28.4 GW 

of additional base load or intermediate load generation capacity 

through 2020, with approximately 0.7 GW of new coal-fired 

capacity, 5.5 GW of new nuclear capacity, and 14.2 GW of new 

NGCC capacity already in development.53 

The change in the resource mix has accelerated in recent 

years, but wind, solar, other renewables, and energy-efficiency 

resources have been reliably participating in the electric 

sector for a number of years. This rapid development of non-

 

51 Bloomberg New Energy Finance and the Business Council for 

Sustainable Energy, 2015 Factbook: Sustainable Energy in 

America, at 16 (2015), available at

http://www.bcse.org/images/2015%20Sustainable%20Energy%20in%20Am

erica%20Factbook.pdf.

52 Energy Information Administration, Electricity: Form EIA-860 

detailed data (Feb. 17, 2015), available at

http://www.eia.gov/electricity/data/eia860/.

53 EIA, Annual Energy Outlook for 2015 with Projections to 2040, 

Final Release, available at

http://www.eia.gov/forecasts/AEO/pdf/0383(2015). The AEO numbers 

include projects that are under development and model-projected 

nuclear, coal, and NGCC projects.
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fossil fuel resources is occurring as much of the existing power 

generation fleet in the U.S. is aging and in need of 

modernization and replacement.54 For example, the average age of 

U.S. coal steam units in 2015 is 45 years.

55 In its 2013 Report 

Card for America’s Infrastructure, the American Society for 

Civil Engineers noted that “America relies on an aging 

electrical grid and pipeline distribution systems, some of which 

originated in the 1880s.”

56 While there has been an increased 

investment in electric transmission infrastructure since 2005, 

the report also found that “ongoing permitting issues, weather 

events, and limited maintenance have contributed to an 

increasing number of failures and power interruptions.”57

However, innovative technologies have increasingly entered the 

electric energy space, helping to provide new answers to how to 

meet the electricity needs of the nation. These new technologies 

can enable the nation to answer not just questions as to how to 

 

54 Quadrennial Energy Review, http://energy.gov/epsa/quadrennialenergy-review-qer

55 We calculated the average age of coal steam units based on the 

NEEDS inventory, and included units with planned retirements in 

2015-2016. See

http://www.epa.gov/airmarkets/documents/ipm/needs_v514.xlsx.

56 American Society for Civil Engineers, 2013 Report Card for 

America’s Infrastructure (2013), available at

http://www.infrastructurereportcard.org/energy/.

57 American Society for Civil Engineers, 2013 Report Card for 

America’s Infrastructure (2013), available at

http://www.infrastructurereportcard.org/energy/.
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reliably meet electricity demand, but also how to meet 

electricity demand reliably and cost-effectively58 with the 

lowest possible emissions and the greatest efficiency. 

Natural gas has a long history of meeting electricity 

demand in the U.S. with a rapidly growing role as domestic 

supplies of natural gas have dramatically increased. Natural gas 

net generation increased by approximately 36 percent between 

2004 and 2014.59 In 2014, natural gas accounted for approximately 

27 percent of net generation.60 The EIA projects that this demand 

growth will continue, with its Annual Energy Outlook 2015 (AEO 

2015) reference case forecasting that natural gas will produce 

31 percent of U.S. electric generation in 2040.61

Renewable sources of electric generation also have a 

history of meeting electricity demand in the U.S. and are 

expected to have an increasing role going forward. A series of 

 

58 Business Council for Sustainable Energy Comments in Docket Id. 

No. EPA-HQ-OAR-2013-0602 at 2 (Nov. 19, 2014).

59 U.S. Energy Information Administration (EIA), Electric Power 

Monthly: Table 1.1 Net Generation by Energy Source: Total (All 

Sectors), 2004-December 2014 (2015), available at

http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=e

pmt_1_1.

60 Id.

61 The AEO 2015 Reference case projection is a business-as-usual 

trend estimate, given known technology and technological and 

demographic trends. EIA explores the impacts of alternative 

assumptions in other cases with different macroeconomic growth 

rates, world oil prices, and resource assumptions. U.S. Energy 

Information Administration (EIA), Annual Energy Outlook 2015 

with Projections to 2040, at 24-25 (2015), available at

http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf.
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energy crises provided the impetus for renewable energy 

development in the early 1970s. The OPEC oil embargo in 1973 and 

oil crisis of 1979 caused oil price spikes, more frequent energy 

shortages, and significantly affected the national and global 

economy. In 1978, partly in response to fuel security concerns, 

Congress passed the Public Utilities Regulatory Policies Act 

(PURPA) which required local electric utilities to buy power 

from qualifying facilities (QFs).62 QFs were either cogeneration 

facilities63 or small generation resources that use renewables 

such as wind, solar, biomass, geothermal, or hydroelectric power 

as their primary fuels.64 Through PURPA, Congress supported the 

development of more renewable energy generation in the U.S. 

States have taken a significant lead in requiring the 

development of renewable resources. In particular, a number of 

states have adopted renewable portfolio standards (RPS). As of 

2013, 29 states and the District of Columbia have enforceable 

RPS or similar laws.65 In its AEO 2015 Reference case, the EIA 

found that renewable energy will account for 38 percent of the 

 

62 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 220-221 (2d ed. 2010).

63 Cogeneration facilities utilize a single source of fuel to 

produce both electricity and another form of energy such as heat 

or steam. Casazza, J. and Delea, F., Understanding Electric 

Power Systems, IEEE Press, at 220-221 (2d ed. 2010).

64 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 220-221 (2d ed. 2010).

65 U.S. Energy Information Administration (EIA), Annual Energy 

Outlook 2014 with Projections to 2040, at LR-5 (2014). 
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overall growth in electricity generation from 2013 to 2040.66 The 

AEO 2015 Reference case forecasts that the renewables share of 

U.S. electricity generation will grow from 13 percent in 2013 to 

18 percent in 2040.67

Price pressures caused by oil embargoes in the 1970s also 

brought the issues of conservation and energy efficiency to the 

forefront of U.S. energy policy.68 This trend continued in the 

early 1990s. Some state regulatory commissions and utilities 

supported energy efficiency through least-cost planning, with 

the National Association of Regulatory Utility Commissioners 

(NARUC) “adopting a resolution that called for the utility’s 

least cost plan to be the utility’s most profitable plan.”69 

 

66 U.S. Energy Information Administration (EIA), Annual Energy 

Outlook 2015 with Projections to 2040, at E-12(2015).

67 U.S. Energy Information Administration (EIA), Annual Energy 

Outlook 2015 with Projections to 2040, at 24-25(2015).

68 Edison Electric Institute, Making a Business of Energy 

Efficiency: Sustainable Business Models for Utilities, at 1 

(2007). Congress passed legislation in the 1970s that 

jumpstarted energy efficiency in the U.S. For example, 

President Ford signed the Energy Policy and Conservation Act 

(EPCA) of 1975 – the first law on the issue. EPCA authorized 

the Federal Energy Administration (FEA) to “develop energy 

conservation contingency plans, established vehicle fuel economy 

standards, and authorized the creation of efficiency standards 

for major household appliances.” Alliance to Save Energy, 

History of Energy Efficiency, at 6 (2013) (citing Anders, “The 

Federal Energy Administration,” 5; Energy Policy and 

Conservation Act, S. 622, 94th Cong. (1975-1976)), available at

https://www.ase.org/sites/ase.org/files/resources/Media%20browse

r/ee_commission_history_report_2-1-13.pdf.

69 Edison Electric Institute, Making a Business of Energy 

Efficiency: Sustainable Business Models for Utilities, at 1 
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Energy efficiency has been utilized to meet energy demand to 

varying levels since that time. As of April 2014, 25 states70

have “enacted long-term (3+ years), binding energy savings 

targets, or energy efficiency resource standards (EERS).”71 

Funding for energy efficiency programs has grown rapidly in 

recent years, with budgets for electric efficiency programs 

totaling $5.9 billion in 2012.72

Advancements and innovation in power sector technologies 

provide the opportunity to address CO2 emission levels at 

affected power plants while at the same time improving the 

overall power system in the U.S. by lowering the carbon 

intensity of power generation, and ensuring a reliable supply of 

power at a reasonable cost.

 

(2007), available at 

http://www.eei.org/whatwedo/PublicPolicyAdvocacy/StateRegulation

/Documents/Making_Business_Energy_Efficiency.pdf.

70 American Council for an Energy-Efficient Economy, State Energy 

Efficiency Resource Standards (EERS) (2014), available at 

http://aceee.org/files/pdf/policy-brief/eers-04-2014.pdf. ACEEE 

did not include Indiana (EERS eliminated), Delaware (EERS 

pending), Florida (programs funded at levels far below what is 

necessary to meet targets), Utah, or Virginia (voluntary 

standards) in its calculation.

71 American Council for an Energy-Efficient Economy, State Energy 

Efficiency Resource Standards (EERS) (2014), available at 

http://aceee.org/files/pdf/policy-brief/eers-04-2014.pdf.

72 American Council for an Energy-Efficient Economy, The 2013 

State Energy Efficiency Scorecard, at 17 (Nov. 2013), available 

at

http://aceee.org/sites/default/files/publications/researchreport

s/e13k.pdf.
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2. Fossil Fuel-fired EGUs Regulated by this Action, Generally

Natural gas-fired EGUs typically use one of two 

technologies: NGCC or simple cycle combustion turbines. NGCC 

units first generate power from a combustion turbine (the 

combustion cycle). The unused heat from the combustion turbine 

is then routed to a heat recovery steam generator (HRSG) that 

generates steam, which is then used to produce power using a 

steam turbine (the steam cycle). Combining these generation 

cycles increases the overall efficiency of the system. Simple 

cycle combustion turbines use a single combustion turbine to 

produce electricity (i.e., there is no heat recovery or steam 

cycle). The power output from these simple cycle combustion 

turbines can be easily ramped up and down making them ideal for 

“peaking” operations.

Coal-fired utility boilers are primarily either pulverized 

coal (PC) boilers or fluidized bed (FB) boilers. At a PC boiler, 

the coal is crushed (pulverized) into a powder in order to 

increase its surface area. The coal powder is then blown into a 

boiler and burned. In a coal-fired boiler using FB combustion, 

the coal is burned in a layer of heated particles suspended in 

flowing air.

Power can also be generated using gasification technology. 

An IGCC unit gasifies coal or petroleum coke to form a synthetic 

gas (or syngas) composed of carbon monoxide (CO) and hydrogen
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(H2), which can be combusted in a combined cycle system to 

generate power.

3. Technological Developments and Costs

Natural gas prices have decreased dramatically and 

generally stabilized in recent years as new drilling techniques 

have brought additional supply to the marketplace and greatly 

increased the domestic resource base. As a result, natural gas 

prices are expected to be competitive for the foreseeable 

future, and EIA modeling and utility announcements confirm that 

utilities are likely to rely heavily on natural gas to meet new 

demand for electricity generation. On average, as discussed 

below, the cost of generation from a new natural-gas fired power 

plant (a NGCC unit) is expected to be significantly lower than 

the cost of generation from a new coal-fired power plant.73

Other drivers that may influence decisions to build new 

power plants are increases in renewable energy supplies, often 

due to state and federal energy policies. As previously 

discussed, many states have adopted RPS, which require a certain 

portion of electricity to come from renewable energy sources 

such as solar or wind. The federal government has also offered

incentives to encourage further deployment of other forms of

 

73 Levelized Cost and Levelized Avoided Cost of New Generation 

Resources in the Annual Energy Outlook 2015

http://www.eia.gov/forecasts/aeo/electricity_generation.html.
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electric generation including renewable energy sources and new 

nuclear power plants. 

Reflecting these factors, the EIA projections from the last 

several years show that natural gas is likely to be the most 

widely-used fossil fuel for new construction of electric 

generating capacity through 2020, along with renewable energy, 

nuclear power, and a limited amount of coal with CCS.74

While EIA data shows that natural gas is likely to be the 

most widely-used fossil fuel for new construction of electric 

generating capacity through 2030, a few coal-fired units still 

remain as viable projects at various advanced stages of 

construction and development. One new coal facility that has 

essentially completed construction, Southern Company's Kemper 

County Energy Facility, deploys IGCC with partial CCS.

Additionally, another project, Summit Power's Texas Clean Energy 

Project (TCEP), which will deploy IGCC with CCS, continues as a

viable project.

75 The EIA modeling projects that coal-fired power 

generation will remain the single largest portion of the 

electricity sector beyond 2030. The EIA modeling also projects 

 

74 http://www.eia.gov/forecasts/aeo/pdf/0383(2013).pdf;

http://www.eia.gov/forecasts/aeo/pdf/0383(2012).pdf;

http://prod-http-80-800498448.us-east1.elb.amazonaws.com/w/images/6/6d/0383%282011%29.pdf.

75 “Odessa coal-to-gas power plant to break ground this year”, 

Houston Chronicle (April 1, 2015).
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that few, if any, new coal-fired EGUs will be built in this 

decade and that those that are built will have CCS.76 Continued 

progress on these projects is consistent with the EIA modeling 

that suggests that a small number of coal-fired power plants may 

be constructed. The primary reasons for this rate of current and 

projected future development of new coal projects include highly 

competitive natural gas prices, lower electricity demand growth, 

and increases in the supply of renewable energy. We recognize, 

however, that a variety of factors may come into play in a 

decision to build new power generation, and we want to ensure 

that there are standards in place to make sure that whatever 

fuel is utilized is done so in a way that minimizes CO2

emissions, as Congress intended with CAA section 111.77

4. Energy Sector Modeling

Various energy sector modeling efforts, including 

projections from the EIA and the EPA, forecast trends in new 

 

76 This projection is for business as usual and does not account 

for the proposed or final CO2 emission standard. Even in its 

sensitivity analysis that assumes higher natural gas prices and 

electricity demand, EIA does not project any additional coalfired power plants beyond its reference case until 2023, in a 

case where power companies assume no GHGs emission limitations, 

and until 2024 in a case where power companies do assume GHGs 

emission limitations.

77 These sources received federal assistance under EPAct 2005. 

See Section III.H.3.g below. However, none of the constraints in 

that Act affect the discussion in the text above, since that 

discussion does not relate to technology use or emissions 

reduction by these sources.
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power plant construction and utilization of existing power 

plants that are consistent with the above-described 

technological developments and costs. The EIA’s annual report, 

the AEO, forecasts the structure of and developments in the 

power sector. These reports are based on economic modeling that 

reflects existing policy and regulations, such as state RPS 

programs and federal tax credits for renewables.78 The current 

report, AEO 201579: (i) shows that a modest amount of coal-fired 

power plants that are currently under construction are expected 

to begin operation in the next several years (referred to as 

“planned”); and (ii) projects in the reference case80 that a very 

small amount of new (“unplanned”) conventional coal-fired 

capacity, with CCS, will come online after 2012 and through 2037 

in response to federal and state incentives. According to the 

AEO 2015, the vast majority of new generating capacity during 

this period will be either natural gas-fired or renewable

sources. Similarly, the EIA projections from the last several 

years show that natural gas is likely to be the most widely-used 

 

78 http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm.

79 Energy Information Administration’s Annual Energy Outlook for 

2015, Final Release available at 

http://www.eia.gov/forecasts/aeo/index.cfm.

80 EIA’s reference case projections are the result of its 

baseline assumptions for economic growth, fuel supply, 

technology, and other key inputs.
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fossil fuel for new construction of electric generating capacity 

through 2030.

81

Specifically, the AEO 2015 projects 30.3 GW of additional 

base load or intermediate load generation capacity through 2020 

(this includes projects that are under development – i.e., being 

constructed or in advance planning - and model-projected 

nuclear, coal, and NGCC projects). The vast majority of this new 

electric capacity (20.4 GW) is already under development (under 

construction or in advanced planning); it includes about 0.7 GW 

of new coal-fired capacity, 5.5 GW of new nuclear capacity, and 

14.2 GW of new NGCC capacity. The EPA believes that most current 

fossil fuel-fired projects are already designed to meet limits 

consistent with this rule (or they have already commenced 

construction and are thus not subject to these final standards).

The AEO 2015 also projects an additional 9.9 GW of new base load 

capacity additions, which are model-projected (unplanned). This 

consists of 7.7 GW of new NGCC capacity, 1.2 GW of new 

geothermal capacity, 0.7 GW of new hydroelectric capacity, and 

0.3 GW of new coal equipped with CCS (incentivized with some 

government funding). Therefore, the AEO 2015 projection suggests 

that the new power generation capacity added through 2020 is 

expected to already meet the final emissions standards without 

 

81 Annual Energy Outlook 2010, 2011, 2012, 2013, 2014 and 2015.
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incurring further control costs. This is also true during the 

period from 2020 through 2030, where new model-projected 

(unplanned) intermediate and base load capacity is expected to 

be compliant with the standards without incurring further 

control costs (i.e., an additional 31.3 GW of NGCC and no 

additional coal, for a total, from 2015 through 2030, of 39 GW 

of NGCC and 0.3 GW of coal with CCS).

Under the EIA projections, existing coal-fired generation 

will remain an important part of the mix for power generation. 

Modeling from both the EIA and the EPA project that coal-fired 

generation will remain the largest single source of electricity 

in the U.S. through 2040. Specifically, in the EIA’s AEO 2015, 

coal will supply approximately 40 percent of all electricity in 

the electric power sector in both 2020 and 2025.

The EPA modeling using the Integrated Planning Model (IPM), 

a detailed power sector model that the EPA uses to support power 

sector regulations, also shows limited future construction of 

new coal-fired power plants under the base case.82 The EPA’s 

projections from IPM can be found in the RIA.

5. Integrated Resource Plans

The trends in the power sector described above are also 

apparent in publicly available long-term resource plans, known 

 

82 http://www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html#documentation.
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as integrated resource plans (IRPs).

The EPA has reviewed publicly available IRPs from a range 

of companies (e.g., varying in size, location, current fuel 

mix), and these plans are generally consistent with both EIA and 

EPA modeling projections.83 These IRPs indicate that companies

are focused on demand-side management programs to lower future 

electricity demand and are mostly reliant on a mix of new 

natural gas-fired generation and renewable energy to meet 

increased load demand and to replace retired generation 

capacity.

Notwithstanding this clear trend towards natural gas-fired 

generation and renewables, many of the IRPs highlight the value 

of fuel diversity and include options to diversify new 

generation capacity beyond natural gas and renewable energy. 

Several IRPs indicate that companies are considering new nuclear 

generation, including either traditional nuclear power plants or 

small modular reactors, and a smaller number are considering new 

coal-fired generation capacity with and without CCS technology. 

Based on public comments and on the information contained in

these IRPs, the EPA acknowledges that a small number of new 

coal-fired power plants may be built in the near future. While 

 

83 Technical Support Document - “Review of Electric Utility 

Integrated Resource Plans” (May 2015), available in the 

rulemaking docket EPA-HQ-OAR-2013-0495.
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this outcome would be contrary to the economic modeling 

predictions, the agency understands that economic modeling may 

not fully reflect the range of factors that a particular company 

may consider when evaluating new generation options, such as 

fuel diversification. Further, it is possible that some of this 

potential new coal-fired construction may occur because 

developers are able to design projects with specific business 

plans, such as the cogeneration of chemicals, which allow the 

source to provide competitively priced electricity in specific 

geographic regions.

D. Statutory Background

The U.S. Supreme Court ruled in Massachusetts v. EPA that 

GHGs84 meet the definition of “air pollutant” in the CAA,85 and 

premised its decision in AEP v. Connecticut,

86 that the CAA 

displaced any federal common law right to compel reductions in 

CO2 emissions from fossil fuel-fired power plants, on its view 

that CAA section 111 applies to GHG emissions.

CAA section 111 authorizes and directs the EPA to prescribe 

new source performance standards (NSPS) applicable to certain 

 

84 The EPA’s 2009 endangerment finding defines the air pollution 

which may endanger public health and welfare as the well-mixed 

aggregate group of the following gases: CO2, methane (CH4), 

nitrous oxide (N2O), sulfur hexafluoride (SF6), 

hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs).

85 549 U.S. 497, 520 (2007).

86 131 S.Ct. 2527, 2537-38 (2011).
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new stationary sources (including newly constructed, modified 

and reconstructed sources).87 As a preliminary step to 

regulation, the EPA must list categories of stationary sources 

that the Administrator, in his or her judgment, finds “cause[], 

or contribute[] significantly to, air pollution which may 

reasonably be anticipated to endanger public health or welfare.”

The EPA has listed and regulated more than 60 stationary source 

categories under CAA section 111.88 The EPA listed the two source 

categories at issue here in the 1970s - listing fossil fuelfired electric steam generating units in 1971 89 and listing

combustion turbines in 1977.

90

Once the EPA has listed a source category, the EPA proposes 

and then promulgates “standards of performance” for “new 

sources” in the category.

91 A “new source” is “any stationary 

source, the construction or modification of which is commenced 

after,” in general, final standards applicable to that source 

are promulgated or, if earlier, proposed.92 A modification is 

“any physical change ... or change in the method of operation 

... which increases the amount of any air pollutant emitted by 

such source or which results in the emission of any air 

 

87 CAA section 111(b)(1)(A). 

88 See generally 40 CFR part 60, subparts D-MMMM.

89 36 FR 5931 (March 31, 1971).

90 42 FR 53657 (October 3, 1977).

91 CAA section 111(b)(1)(B).

92 CAA section 111(a)(2).
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pollutant not previously emitted.”93 The EPA, through 

regulations, has determined that certain types of changes are 

exempt from consideration as a modification.94

The NSPS general provisions (40 CFR part 60, subpart A)

provide that an existing source is considered to be a new source 

if it undertakes a “reconstruction,” which is the replacement of 

components of an existing facility to an extent that (1) the 

fixed capital cost of the new components exceeds 50 percent of 

the fixed capital cost that would be required to construct a 

comparable entirely new facility, and (2) it is technologically 

and economically feasible to meet the applicable standards.95

CAA section 111(a)(1) defines a “standard of performance” 

as “a standard for emissions of air pollutants which reflects 

the degree of emission limitation achievable through the 

application of the best system of emission reduction which 

(taking into account the cost of achieving such reduction and 

any non-air quality health and environmental impact and energy 

requirements) the Administrator determines has been adequately 

demonstrated.” This definition makes clear that the standard of 

 

93 CAA section 111(a)(4); See also 40 CFR 60.14 concerning what 

constitutes a modification, how to determine the emission rate, 

how to determine an emission increase, and specific actions that 

are not, by themselves, considered modifications.

94 40 CFR 60.2, 60.14(e).

95 40 CFR 60.15.
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performance must be based on “the best system of emission 

reduction . . . adequately demonstrated” (BSER).

The standard that the EPA develops, reflecting the 

performance of the BSER, is commonly a numeric emission limit, 

expressed as a numeric performance level that can either be 

normalized to a rate of output or input (e.g., tons of pollution 

per amount of product produced – a so-called rate-based 

standard), or expressed as a numeric limit on mass of pollutant 

that may be emitted (e.g., 100 ug/m3 – parts per billion). 

Generally, the EPA does not prescribe a particular technological 

system that must be used to comply with a standard of 

performance.96 Rather, sources generally may select any measure 

or combination of measures that will achieve the emissions level 

of the standard.97 In establishing standards of performance, the 

EPA has significant discretion to create subcategories based on 

source type, class, or size.98

The text and legislative history of CAA section 111, as 

well as relevant court decisions, identify the factors that the 

EPA is to consider in making a BSER determination. The system of 

emission reduction must be technically feasible, the costs of 

the system must be reasonable, and the emission standard that 

 

96 CAA section 111(b)(5) and (h).

97 CAA section 111(b)(5).

98 CAA section 111(b)(2); see also Lignite Energy Council v. EPA, 

198 F. 3d 930, 933 (D.C. Cir. 1999).
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the EPA promulgates based on the system of emission reduction 

must be achievable. In addition, in identifying a BSER, the EPA 

must consider the amount of emissions reductions attributable to

the system, and must also consider non-air quality health and 

environmental impacts and energy requirements. The case law 

addressing CAA section 111 makes it clear that the EPA has 

discretion in weighing costs, amount of emission reductions, 

energy requirements, and impacts of non-air quality pollutants, 

and may weigh them differently for different types of sources or 

air pollutants. We note that under the case law of the D.C. 

Circuit, another factor is relevant for the BSER determination: 

whether the standard would effectively promote further 

deployment or development of advanced technologies. Within the 

constraints just described, the EPA has discretion in 

identifying the BSER and the resulting emission standard. See 

generally Section III.H below.

For more than four decades, the EPA has used its authority 

under CAA section 111 to set cost-effective emission standards 

which ensure that newly constructed, reconstructed, and modified 

stationary sources use the best performing technologies to limit 

emissions of harmful air pollutants. In this final action, the 

EPA is following the same well-established interpretation and 

application of the law under CAA section 111 to address GHG 

emissions from newly constructed, reconstructed, and modified 
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fossil fuel-fired power plants. For each of the standards in 

this final action, the EPA considered a number of alternatives 

and evaluated them against the statutory factors. The BSER for

each category of affected EGUs and the standards of performance 

based on these BSER are based on that evaluation.

E. Regulatory Background

In 1971, the EPA initially included fossil fuel-fired EGUs 

(which includes natural gas, petroleum and coal) that use steamgenerating boilers in a category that it listed under CAA 

section 111(b)(1)(A),99 and promulgated the first set of 

standards of performance for sources in that category, which it 

codified in subpart D.100 In 1977, the EPA initially included 

fossil fuel-fired combustion turbines in a category that the EPA 

listed under CAA section 111(b)(1)(A),101 and the EPA promulgated 

standards of performance for that source category in 1979, which 

the EPA codified in subpart GG.102

The EPA has revised those regulations, and in some 

instances, has revised the codifications (that is, the 40 CFR 

 

99 36 FR 5931 (March 31, 1971).

100 “Standards of Performance for Fossil-Fuel-Fired Steam 

Generators for Which Construction Is Commenced After August 17, 

1971,” 36 FR 24875 (December 23, 1971) codified at 40 CFR 60.40-

46.

101 42 FR 53657 (October 3, 1977).

102 “Standards of Performance for Electric Utility Steam 

Generating Units for Which Construction is Commenced After 

September 18, 1978,” 44 FR 33580 (June 11, 1979).
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part 60 subparts), several times over the ensuing decades. In 

1979, the EPA divided subpart D into 3 subparts – Da (“Standards 

of Performance for Electric Utility Steam Generating Units for 

Which Construction is Commenced After September 18, 1978”), Db 

(“Standards of Performance for Industrial-CommercialInstitutional Steam Generating Units”) and Dc (“Standards of 

Performance for Small Industrial-Commercial-Institutional Steam 

Generating Units”) – in order to codify separate requirements 

that it established for these subcategories.103 In 2006, the EPA 

created subpart KKKK, ”Standards of Performance for Stationary 

Combustion Turbines,” which applied to certain sources 

previously regulated in subparts Da and GG.

104 None of these 

subsequent rulemakings, including the revised codifications, 

however, constituted a new listing under CAA section 

111(b)(1)(A).

The EPA promulgated amendments to subpart Da in 2006, which 

included new standards of performance for criteria pollutants 

for EGUs, but did not include specific standards of performance 

for CO2 emissions.105 Petitioners sought judicial review of the 

 

103 44 FR 33580 (June 11, 1979).

104 71 FR 38497 (July 6, 2006), as amended at 74 FR 11861 (March 

20, 2009).

105 ”Standards of Performance for Electric Utility Steam 

Generating Units, Industrial-Commercial-Institutional Steam 

Generating Units, and Small Industrial-Commercial-Institutional 
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rule, contending, among other issues, that the rule was required 

to include standards of performance for GHG emissions from 

EGUs.106 The January 8, 2014 preamble to the proposed CO2

standards for new EGUs107 includes a discussion of the GHGrelated litigation of the 2006 Final Rule as well as other GHGassociated litigation.

F. Development of Carbon Pollution Standards for Fossil Fuelfired Electric Utility Generating Units 

On April 13, 2012, the EPA initially proposed standards 

under CAA section 111 for newly constructed fossil fuel-fired 

electric utility steam generating units. 77 FR 22392 (“April 

2012 proposal”). The EPA withdrew that proposal (79 FR 1352 

(January 8, 2014)), and, on the same day, proposed the standards 

addressed in this final rule. 79 FR 1430 (“January 2014 

proposal”). Specifically, the EPA proposed standards under CAA 

section 111 to limit emissions of CO2 from newly constructed 

fossil fuel-fired electric utility steam generating units and 

newly constructed natural gas-fired stationary combustion 

turbines. 

In support of the January 2014 proposal, on February 26, 

2014, the EPA published a notice of data availability (NODA) (79 

 

Steam Generating Units, Final Rule.” 71 FR 9866 (February 27, 

2006).

106 State of New York, et al. v. EPA, No. 06–1322. 

107 79 FR 1430, 1444.
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FR 10750). Through the NODA and an associated technical support 

document, Effect of EPAct05 on Best System of Emission Reduction 

for New Power Plants, the EPA solicited comment on its 

interpretation of the provisions in the Energy Policy Act of 

2005 (EPAct05),

108 including how the provisions may affect the 

rationale for the EPA’s proposed determination that partial CCS 

is the best system of emission reduction adequately demonstrated 

for fossil fuel-fired electric utility steam generating units.

On June 18, 2014, the EPA proposed standards of performance 

to limit emissions of CO2 from modified and reconstructed fossil 

fuel-fired electric utility steam generating units and natural 

gas-fired stationary combustion turbines (79 FR 34960; June 2014 

proposal). Specifically, the EPA proposed standards of 

performance for: (1) modified fossil fuel-fired electric utility 

steam generating units, (2) modified natural gas-fired 

stationary combustion turbines, (3) reconstructed fossil fuelfired electric utility steam generating units, and (4) 

reconstructed natural gas-fired stationary combustion turbines.

 

108 See Section III.H.3.g below. The Energy Policy Act of 2005 

(EPAct05) was signed into law by President George W. Bush on 

August 8, 2005. EPAct05 was intended to address energy 

production in the United States, including: (1) energy 

efficiency; (2) renewable energy; (3) oil and gas; (4) coal; (5) 

Tribal energy; (6) nuclear matters and security; (7) vehicles 

and motor fuels, including ethanol; (8) hydrogen; (9) 

electricity; (10) energy tax incentives; (11) hydropower and 

geothermal energy; and (12) climate change technology.

www2.epa.gov/laws-regulations/summary-energy-policy-act.
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G. Stakeholder Engagement and Public Comments on the Proposals

1. Stakeholder Engagement

The EPA has engaged extensively with a broad range of 

stakeholders and the general public regarding climate change, 

carbon pollution from power plants, and carbon pollution 

reduction opportunities. These stakeholders included industry 

and electric utility representatives, state and local officials, 

tribal officials, labor unions, non-governmental organizations 

and many others.

In February and March 2011, early in the process of 

developing carbon pollution standards for new power plants, the 

EPA held five listening sessions to obtain information and input 

from key stakeholders and the public. Each of the five sessions 

had a particular target audience: the electric power industry, 

environmental and environmental justice organizations, states 

and tribes, coalition groups, and the petroleum refinery 

industry.

The EPA conducted subsequent outreach prior to the June 

2014 proposals of standards for modified and reconstructed EGUs 

and emission guidelines for existing EGUs, as well as during the 

public comment periods for the proposals. Although this 

stakeholder outreach was primarily framed around the GHG 

emission guidelines for existing EGUs, the outreach encompassed 

issues relevant to this rulemaking and provided an opportunity 
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for the EPA to better understand previous state and stakeholder 

experience with reducing CO2 emissions in the power sector. In 

addition to 11 public listening sessions, the EPA held hundreds 

of meetings with individual stakeholder groups, and meetings 

that brought together a variety of stakeholders to discuss a 

wide range of issues related to the electricity sector and 

regulation of GHGs under the CAA. The agency met with electric 

utility associations and electricity grid operators. Agency 

officials engaged with labor unions and with leaders 

representing large and small industries. The agency also met 

with energy industries, such as coal and natural gas interests, 

as well as with representatives of energy-intensive industries, 

such as the iron and steel, and aluminum industries, to better

understand the potential concerns of large industrial purchasers 

of electricity. In addition, the agency met with companies that 

offer new technology to prevent or reduce carbon pollution. The 

agency provided and encouraged multiple opportunities for 

engagement with state, local, tribal, and regional environmental 

and energy agencies. The EPA also met with representatives of 

environmental justice organizations, environmental groups, 

public health professionals, public health organizations,

religious organizations, and other community stakeholders.

The EPA received more than 2.5 million comments submitted 

in response to the original April 2012 proposal for newly 
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constructed fossil fuel-fired EGUs. Because the original 

proposal was withdrawn, the EPA instructed commenters that 

wanted their comments on the April 2012 proposal to be 

considered in connection with the January 2014 proposal to 

submit new comments to the EPA or to re-submit their previous 

comments. We received more comments in response to the January 

2014 proposal, as discussed in the section below.

The EPA has given stakeholder input provided prior to the 

proposals, as well as during the public comment periods for each 

proposal, careful consideration during the development of this 

rulemaking and, as a result, it includes elements that are 

responsive to many stakeholder concerns and that enhance the 

rule. This preamble and the Response-to-Comments (RTC) document 

summarize and provide the agency’s responses to the comments 

received. 

2. Comments on the January 2014 Proposal for Newly Constructed 

Fossil Fuel-fired EGUs

Upon publication of the January 8, 2014 proposal for newly 

constructed fossil fuel-fired EGUs, the EPA provided a 60-day 

public comment period. On March 6, 2014, in order to provide the 

public additional time to submit comments and supporting 

information, the EPA extended the comment period by 60 days, to 

May 9, 2014, giving stakeholders over 120 days to review, and 

comment upon, the January 2014 proposal, as well as the NODA. A 
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public hearing was held on February 6, 2014, with 159 speakers 

presenting testimony. 

 The EPA received more than 2 million comments on the 

proposed standards for newly constructed fossil fuel-fired EGUs 

from a range of stakeholders that included industry and electric 

utility representatives, trade groups, equipment manufacturers, 

state and local government officials, academia, environmental 

organizations, and various interest groups. The agency received 

comments on a range of topics, including the determination that 

a new highly-efficient steam generating EGU implementing partial 

CCS was the BSER for such sources, the level of the CO2 standard 

based on implementation of partial CCS, the criteria that define

which newly constructed natural gas-fired stationary combustion 

turbines will be subject to standards, the establishment of 

subcategories based on combustion turbine size, and the rule’s 

potential effects on the Prevention of Significant Deterioration 

(PSD) preconstruction permit program and Title V operating 

permit program.

3. Comments on the June 2014 Proposal for Modified and 

Reconstructed Fossil Fuel-fired EGUs

 Upon publication of the June 18, 2014 proposal for modified 

and reconstructed fossil fuel-fired EGUs, the EPA offered a 120-

day public comment period - through October 16, 2014. The EPA 

held public hearings in four locations during the week of July 
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28, 2014. These hearings also addressed the EPA’s June 18, 2014 

proposed emission guidelines for existing fossil fuel-fired EGUs 

(reflecting the connections between the proposed standards for 

modified and reconstructed sources and the proposed emission 

guidelines). A total of 1,322 speakers testified, and a further 

1,450 attended but did not speak. The speakers were provided the 

opportunity to present data, views, or arguments concerning one 

or both proposed actions.

 The EPA received over 200 comments on the proposed 

standards for modified and reconstructed fossil fuel-fired EGUs 

from a range of stakeholders similar to those that submitted 

comments on the January 2014 proposal for newly constructed 

fossil fuel-fired EGUs (i.e., industry and electric utility 

representatives, trade groups, equipment manufacturers, state 

and local government officials, academia, environmental 

organizations, and various interest groups). The agency received 

comments on a range of topics, including the methodology for 

determining unit-specific CO2 standards for modified steam 

generating units and the use of supercritical boiler conditions 

as the basis for the CO2 standards for certain reconstructed 

steam generating units. Many of the comments regarding modified 

and reconstructed natural gas-fired stationary combustion 

turbines are similar to the comments regarding newly constructed 
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combustion turbines described above (e.g., applicability 

criteria and subcategories based on turbine size). 

III. Regulatory Authority, Affected EGUs and Their Standards, 

and Legal Requirements

In this section, we describe our authority to regulate CO2

from fossil fuel-fired EGUs. We also describe our decision to 

combine the two existing categories of affected EGUs – steam 

generators and combustion turbines - into a single category of 

fossil fuel-fired EGUs for purposes of promulgating standards of 

performance for CO2 emissions. We also explain that we are 

codifying all of the requirements in this rule for new,

modified, and reconstructed affected EGUs in new subpart TTTT of 

part 60 of Title 40 of the Code of Federal Regulations. In 

addition, we explain which sources are and are not affected by 

this rule, and the format of these standards. Finally, we 

describe the legal requirements for establishing these emission 

standards.

A. Authority to Regulate Carbon Dioxide from Fossil Fuel-fired

EGUs

The EPA’s authority for this rule is CAA section 111(b)(1). 

CAA section 111(b)(1)(A) requires the Administrator to establish 

a list of source categories to be regulated under section 111. 

A category of sources is to be included on the list “if in [the 

Administrator’s] judgment it causes, or contributes 
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significantly to, air pollution which may reasonably be 

anticipated to endanger public health and welfare.” This 

determination is commonly referred to as an “endangerment 

finding” and that phrase encompasses both the “causes or 

contributes significantly” component and the “endanger public 

health and welfare” component of the determination. Then, for 

the source categories listed under section 111(b)(1)(A), the 

Administrator promulgates, under section 111(b)(1)(B), 

“standards of performance for new sources within such category.”

In this rule, the EPA is establishing standards under 

section 111(b)(1)(B) for source categories that it has

previously listed and regulated for other pollutants and which 

now are being regulated for an additional pollutant. Because of 

this, there are two aspects of section 111(b)(1) that warrant 

particular discussion.

First, because the EPA is not listing a new source category 

in this rule, the EPA is not required to make a new endangerment 

finding with regard to affected EGUs in order to establish 

standards of performance for the CO2 emissions from those 

sources. Under the plain language of CAA section 111(b)(1)(A), 

an endangerment finding is required only to list a source 

category. Further, though the endangerment finding is based on 

determinations as to the health or welfare impacts of the 

pollution to which the source category’s pollutants contribute, 
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and as to the significance of the amount of such contribution, 

the statute is clear that the endangerment finding is made with 

respect to the source category; section 111(b)(1)(A) does not 

provide that an endangerment finding is made as to specific 

pollutants. This contrasts with other CAA provisions that do 

require the EPA to make endangerment findings for each 

particular pollutant that the EPA regulates under those 

provisions. E.g., CAA sections 202(a)(1), 211(c)(1), and 

231(a)(2)(A); see also American Electric Power Co. Inc., v. 

Connecticut, 131 S. Ct. 2527, 2539 (2011) (“[T]he Clean Air Act 

directs the EPA to establish emissions standards for categories

of stationary sources that, ‘in [the Administrator's] judgment,’ 

‘caus[e], or contribut[e] significantly to, air pollution which 

may reasonably be anticipated to endanger public health or 

welfare.’ § 7411(b)(1)(A).”) (emphasis added).

Second, once a source category is listed, the CAA does not 

specify what pollutants should be the subject of standards from 

that source category. The statute, in section 111(b)(1)(B), 

simply directs the EPA to propose and then promulgate 

regulations “establishing federal standards of performance for 

new sources within such category.” In the absence of specific 

direction or enumerated criteria in the statute concerning what 

pollutants from a given source category should be the subject of 

standards, it is appropriate for the EPA to exercise its 
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authority to adopt a reasonable interpretation of this 

provision. Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 843-44 

(1984).109

The EPA has previously interpreted this provision as 

granting it the discretion to determine which pollutants should 

be regulated. See Standards of Performance for Petroleum 

Refineries, 73 Fed. Reg. 35838 (June 24, 2008) (concluding that

the statute provides “the Administrator with significant 

flexibility in determining which pollutants are appropriate for 

regulation under section 111(b)(1)(B)” and citing cases). 

Further, in directing the Administrator to propose and 

promulgate regulations under section 111(b)(1)(B), Congress 

provided that the Administrator should take comment and then 

finalize the standards with such modifications “as he deems 

appropriate.” The D.C. Circuit has considered similar statutory 

phrasing from CAA section 231(a)(3) and concluded that “[t]his 

delegation of authority is both explicit and extraordinarily 

broad.” National Assoc. of Clean Air Agencies v. EPA, 489 F.3d 

1221, 1229 (D.C. Cir. 2007).

 

109 In Chevron, the U.S. Supreme Court held that an agency must, 

at Step 1, determine whether Congress’s intent as to the 

specific matter at issue is clear, and, if so, the agency must 

give effect to that intent. If Congressional intent is not 

clear, then, at Step 2, the agency has discretion to fashion an 

interpretation that is a reasonable construction of the statute.
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In exercising its discretion with respect to which 

pollutants are appropriate for regulation under section 

111(b)(1)(B), the EPA has in the past provided a rational basis 

for its decisions. See National Lime Assoc. v. EPA, 627 F.2d 

416, 426 & n.27 (D.C. Cir. 1980) (court discussed, but did not 

review, the EPA’s reasons for not promulgating standards for 

oxides of nitrogen (NOX), sulfur dioxide (SO2) and CO from lime 

plants); Standards of Performance for Petroleum Refineries, 73 

Fed. Reg. at 35859-60 (June 24, 2008) (providing reasons why the 

EPA was not promulgating GHG standards for petroleum refineries 

as part of that rule). Though these previous examples involved 

the EPA providing a rational basis for not setting standards for 

a given pollutant, a similar approach is appropriate where the 

EPA determines that it should set a standard for an additional 

pollutant for a source category that was previously listed and 

regulated for other pollutants.

In this rulemaking, the EPA has a rational basis for 

concluding that emissions of CO2 from fossil fuel-fired power 

plants, which are the major U.S. source of GHG air pollution, 

merit regulation under CAA section 111. As noted, in 2009, the 

EPA made a finding that GHG air pollution may reasonably be 

anticipated to endanger public health or welfare, and in 2010, 

the EPA denied petitions to reconsider that finding. The EPA 

extensively reviewed the available science concerning GHG 
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pollution and its impacts in taking those actions. In 2012, the 

U.S. Court of Appeals for the D.C. Circuit upheld the finding 

and the denial of petitions to reconsider.110 In addition, 

assessments from the NRC, the IPCC, and other organizations

published after 2010 lend further credence to the validity of 

the Endangerment Finding. No information that commenters have 

presented or that the EPA has reviewed provides a basis for 

reaching a different conclusion. Indeed, current and evolving 

science discussed in detail in Section II.A of this preamble is 

confirming and enhancing our understanding of the near- and 

longer-term impacts emissions of CO2 are having on Earth’s 

climate and the adverse public health, welfare, and economic 

consequences that are occurring and are projected to occur as a 

result.

Moreover, the high level of GHG emissions from fossil fuelfired EGUs makes clear that it is rational for the EPA to 

regulate GHG emissions from this sector. EGUs emit almost onethird of all U.S. GHGs and comprise by far the largest 

stationary source category of GHG emissions; indeed, as noted 

above, the CO2 emissions from fossil fuel-fired EGUs are almost 

three times as much as the emissions from the next ten source 

categories combined. Further, the CO2 emissions from even a 

 

110 Coalition for Responsible Regulation v. EPA, 684 F.3d 102, 

119-126 (D.C. Circuit 2012).
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single new coal-fired power plant may amount to millions of tons 

each year. See, e.g., Section V.K below (noting that even the 

difference in CO2 emissions between a highly efficient SCPC and 

the same unit meeting today’s standard of performance can amount 

to hundreds of thousands of tons each year). These facts provide 

a rational basis for regulating CO2 emissions from affected EGUs. 

Some commenters have argued that the EPA is required to 

make a new endangerment finding before it may regulate CO2 from 

EGUs. We disagree, for the reasons discussed above. Moreover, as

discussed in the January 2014 proposal,111 even if CAA section 

111 required the EPA to make endangerment and cause-orcontribute significantly findings as prerequisites for this 

rulemaking, then, so far as the “CO2 endangers public health and 

welfare” component of an endangerment finding is concerned, the 

information and conclusions described above should be considered 

to constitute the requisite endangerment finding. Similarly, so 

far as a cause-or-contribute significantly finding is concerned, 

the information and conclusions described above should be 

considered to constitute the requisite finding. The EPA’s 

rational basis for regulating CO2 under CAA section 111 is based 

primarily on the analysis and conclusions in the EPA’s 2009 

Endangerment Finding and 2010 denial of petitions to reconsider 

 

111 79 FR 1430, 1455-56 (January 8, 2014).
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that Finding, coupled with the subsequent assessments from the 

IPCC and NRC that describe scientific developments since those 

EPA actions. In addition, we have reviewed comments presenting 

other scientific information to determine whether that 

information has any meaningful impact on our analysis and 

conclusions. 

More specifically, our approach here – reflected in the 

information and conclusions described above – is substantially 

similar to that reflected in the 2009 Endangerment Finding and 

the 2010 denial of petitions to reconsider. The D.C. Circuit 

upheld that approach in Coalition for Responsible Regulation v. 

EPA, 684 F.3d 102, 117-123 (D.C. Cir. 2012) (noting, among other 

things, the “substantial ... body of scientific evidence marshaled 

by EPA in support of the Endangerment Finding” (id. at 120); the 

“substantial record evidence that anthropogenic emissions of 

greenhouse gases ‘very likely’ caused warming of the climate 

over the last several decades” (id. at 121); “substantial 

scientific evidence ... that anthropogenically induced climate 

change threatens both public health and public welfare . . . 

[through] extreme weather events, changes in air quality, 

increases in food- and water-borne pathogens, and increases in 

temperatures” (id.); and “substantial evidence ... that the 

warming resulting from the greenhouse gas emissions could be 

expected to create risks to water resources and in general to 
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coastal areas . . . .” (id.)). The facts, unfortunately, have 

only grown stronger and the potential adverse consequences to 

public health and the environment more dire in the interim. 

Accordingly, that approach would support an endangerment finding 

for this rulemaking.112

 

112 Nor does the EPA consider the cost of potential standards of 

performance in making this Finding. Like the Endangerment 

Finding under section 202(a) at issue in State of Massachusetts

v. EPA, 549 U.S. 497 (2007) the pertinent issue is a scientific 

inquiry as to whether an endangerment to public health or 

welfare from the relevant air pollution may reasonably be 

anticipated. Where, as here, the scientific inquiry conducted by 

the EPA indicates that these statutory criteria are met, the 

Administrator does not have discretion to decline to make a 

positive endangerment finding to serve other policy grounds. Id. 

at 532-35. In this regard, an endangerment finding is analogous 

to setting national ambient air quality standards under section 

109(b), which similarly call on the Administrator to set 

standards that in her “judgment” are “requisite to protect the 

public health”. The EPA is not permitted to consider potential 

costs of implementation in setting these standards. Whitman v. 

American Trucking Assn’s, 531 U.S. 457, 466 (2001); see also 

Michigan v. EPA, U.S. (no. 14-46, June 29, 2015) slip op. pp. 

10-11 (reiterating Whitman holding). The EPA notes further that 

section 111(b)(1) contains no terms such as “necessary and 

appropriate” which could suggest (or, in some contexts, require) 

that costs may be considered as part of the finding. Compare CAA 

section 111(n)(1)(A); see State of Michigan, slip op. pp. 7-8. 

The EPA, of course, must consider costs in determining whether a 

best system of emission reduction is adequately demonstrated and 

so can form the basis for a section 111(b) standard of 

performance, and the EPA has carefully considered costs here and 

found them to be reasonable. See section V. H. and I. below. 

The EPA also has found that the rule’s quantifiable benefits 

exceed regulatory costs under a range of assumptions were new 

capacity to be built. RIA chapter 5 and section XIII.G below. 

Accordingly, this endangerment finding would be justified if 

(against our view) it is both required, and (again, against our 

view) costs are to be considered as part of the finding.
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Likewise, if the EPA were required to make a cause-orcontribute-significantly finding for CO2 emissions from the 

fossil fuel-fired EGUs as a prerequisite to regulating such 

emissions under CAA section 111, the same facts that support our 

rational basis determination would support such a finding. As 

shown in Tables 3 and 4 in this preamble, fossil fuel-fired EGUs 

are very large emitters of CO2. All told, these fossil fuel-fired 

EGUs emit almost one-third of all U.S. GHG emissions, and are 

responsible for almost three times as much as the emissions from 

the next ten stationary source categories combined. The CO2

emissions from even a single new coal-fired power plant may 

amount to millions of tons each year, and the CO2 emissions from 

even a single NGCC unit may amount to one million or more tons 

per year. It is not necessary in this rulemaking for the EPA to 

decide whether it must identify a specific threshold for the

amount of emissions from a source category that constitutes a 

significant contribution; under any reasonable threshold or 

definition, the emissions from combustion turbines and steam 

generators are a significant contribution. Indeed, these 

emissions far exceed in magnitude the emissions from motor 

vehicles, which have already been held to contribute to the 

endangerment. See Coalition for Responsible Regulation, 684 F. 

3d at 121 (“substantial evidence” supports the EPA’s 

determination “that motor-vehicle emissions of greenhouse gases 
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contribute to climate change and thus to the endangerment of 

public health and welfare”).113

B. Treatment of Categories and Codification in the Code of 

Federal Regulations 

As discussed in the January 2014 proposal of carbon 

pollution standards for newly constructed EGUs (79 FR 1430) and 

above, in 1971 the EPA listed fossil fuel-fired steam generating 

boilers as a new category subject to CAA section 111 rulemaking, 

and in 1979 the EPA listed fossil fuel-fired combustion turbines 

as a new category subject to the CAA section 111 rulemaking. In 

the ensuing years, the EPA has promulgated standards of 

performance for the two categories and codified those standards, 

 

113 The “air pollution” defined in the Endangerment Finding is 

the atmospheric mix of six long-lived and directly emitted 

greenhouse gases: carbon dioxide (CO2), methane (CH4), nitrous 

oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), 

and sulfur hexafluoride (SF6). See 74 FR 66496 at 66497. The 

standards of performance adopted in the present rulemaking 

address only one component of this air pollution: CO2. This is 

reasonable, given that CO2 is the air pollutant emitted in the 

largest volume by the source category, and which is 

(necessarily) emitted by every affected EGU. There is, of 

course, no requirement that standards of performance address 

each component of the air pollution which endangers. Section 

111(b)(1)(A) requires the EPA to establish “standards of 

performance” for listed source categories, and the definition of 

“standard of performance” in section 111 (a)(1) does not specify 

which air pollutants must be controlled. See also Section III.G 

below explaining that CH4 and N2O emissions represent less than 1 

percent of total estimated GHG emissions (as CO2e) from fossil 

fuel-fired electric power generating units.
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at various times, in 40 CFR part 60, subparts D, Da, GG, and 

KKKK.

In the January 2014 proposal of carbon pollution standards 

for newly constructed EGUs (79 FR 1430) and the June 2014 

proposal of carbon pollution standards for modified and 

reconstructed EGUs (79 FR 34960), the EPA proposed separate 

standards of performance for new, modified, and reconstructed 

sources in the two categories. The EPA took comment on combining 

the two categories into a single category solely for purposes of 

the CO2 emissions from new, modified, and reconstructed affected 

EGUs. In addition, the EPA proposed codifying the standards of 

performance in the same Da and KKKK subparts that currently 

contain the standards of performance for other pollutants from 

those sources addressed in the NSPS program, but co-proposed 

codifying all the standards of performance for CO2 emissions in a 

new 40 CFR part 60 subpart TTTT.

In this rule, the EPA is combining the steam generator and 

combustion turbine categories into a single category of fossil 

fuel-fired electricity generating units for purposes of 

promulgating standards of performance for GHG emissions. 

Combining the two categories is reasonable because they both 

provide the same product: electricity services. Moreover, 

combining them in this rule is consistent with our decision to 

combine them in the CAA section 111(d) rule for existing sources 
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that accompanies this rule. In addition, many of the monitoring, 

reporting, and verification requirements are the same for both 

source categories, and, as discussed next, we are codifying all 

requirements in a single new subpart of the regulations; as a 

result, combining the two categories into a single category will 

reduce confusion. It should be noted that in this rule, we are 

not combining the two categories for purposes of standards of 

performance for other air pollutants.

Because these two source categories are pre-existing listed 

source categories and the EPA will not be subjecting any 

additional sources in the categories to CAA regulation for the 

first time, the combination of these two categories is not 

considered a new source category subject to the listing 

requirements of CAA section 111(b)(1)(A). As a result, this 

final rule does not list a new category under CAA section 

111(a)(1)(A), nor does this final rule revise either of the two 

source categories. Thus, the EPA is not required to make a new 

endangerment and contribution finding for the combination of the 

two categories,

114 although as discussed in the previous section, 

the evidence strongly supports such findings. Thus, the EPA has 

 

114 See, e.g., American Trucking Assn’s v. EPA, 175 F.3d 1027, 

1055, rev’d on other grounds sub. nom. Whitman v. Am. Trucking 

Assn’s, 531.U.S. 457 (because fine particulate matter (PM2.5) was 

already included as a sub-set of the listed pollutant 

particulate matter, it was not a new pollutant necessitating a 

new listing).
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found, in the alternative, that this category of sources

contributes significantly to air pollution which may be 

reasonably anticipated to endanger public health and welfare.

C. Affected Units 

We generally refer to fossil fuel-fired electric generating 

units that would be subject to a CAA section 111 emission 

standard as “affected” or “covered” sources, units, facilities 

or simply as EGUs. An EGU is any boiler, IGCC unit, or 

combustion turbine (in either simple cycle or combined cycle 

configuration) that meets the applicability criteria. Affected 

EGUs include those that commenced construction after January 8, 

2014, and meet the specified applicability criteria and, for 

modifications and reconstructions, EGUs that commenced those 

activities after June 18, 2014, and meet the specified 

applicability criteria.

To be considered an EGU, the unit must: (1) be capable of 

combusting more than 250 MMBtu/h (260 GJ/h) heat input of fossil 

fuel;

115 and (2) serve a generator capable of supplying more than 

25 MW net to a utility distribution system (i.e., for sale to 

the grid).116 However, we are not finalizing CO2 standards for 

 

115 We refer to the capability to combust 250 MMBtu/h of fossil 

fuel as the "base load rating criterion." Note that 250 MMBtu/h 

is equivalent to 73 MW or 260 GJ/h heat input.

116 We refer to the capability to supply 25 MW net to the grid as 

the "total electric sales criterion."
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certain EGUs. The EGUs that are not covered by the standards we 

are finalizing in this rule include: (1) non-fossil fuel units 

subject to a federally enforceable permit that limits the use of 

fossil fuels to 10 percent or less of their heat input capacity 

on an annual basis; (2) combined heat and power (CHP) units that 

are subject to a federally enforceable permit limiting annual 

net-electric sales to no more than the unit’s design efficiency 

multiplied by its potential electric output, or 219,000 MWh or

less, whichever is greater; (3) stationary combustion turbines 

that are not physically capable of combusting natural gas (e.g., 

not connected to a natural gas pipeline); (4) utility boilers 

and IGCC units that have always been subject to a federally 

enforceable permit limiting annual net-electric sales to onethird or less of their potential electric output (e.g., limiting 

hours of operation to less than 2,920 hours annually) or 

limiting annual electric sales to 219,000 MWh or less; (5)

municipal waste combustors that are subject to subpart Eb of 

this part; and (6) commercial or industrial solid waste 

incineration units subject to subpart CCCC of this part.

D. Units Not Covered by this Final Rule

As described in the previous section, the EPA is not 

issuing standards of performance for certain types of sources –

specifically, dedicated non-fossil fuel-fired (e.g., biomass) 

units and industrial CHP units, as well as certain projects 
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under development. This section discusses these sources and our 

rationale for not issuing standards for them. Because the 

rationale applies to both steam generating units and combustion 

turbines, we are describing it here rather than in the separate 

steam generating unit and combustion turbine discussions. We 

discuss the proposed applicability criteria, the topics where 

the agency solicited comment, a brief summary of the relevant 

comments, and the rationale for the final applicability approach 

for these sources. 

1. Dedicated Non-fossil Fuel Units

The proposed applicability for newly constructed EGUs 

included those that primarily combust fossil fuels (e.g., coal, 

oil, and natural gas). The proposed applicability criteria were

that affected units must burn fossil fuels for more than 10

percent of the unit’s total heat input, on average, over a 3-

year period.

117 Under the proposed approach, applicability under

the final NSPS for CO2 emissions could have changed on an annual 

basis depending on the composition of fuel burned. We solicited 

comment on several aspects of the proposed applicability 

criteria for non-fossil fuel units. Specifically, we solicited 

comment on a broad applicability approach that would include 

non-fossil fuel-fired units as affected units, but that would 

 

117 We refer to the fraction of heat input derived from fossil 

fuels as the "fossil fuel-use criterion." 
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impose an alternate standard when the unit fires fossil fuels 

for 10 percent or less of the heat input during the 3-year 

applicability-determination period. We solicited comment on 

whether, if such a subcategory is warranted, the applicabilitydetermination period for the subcategory should be 1-year or a 

3-year rolling period. We also solicited comment on whether the 

standard for such a subcategory should be an alternate numerical 

limit or "no emission standard."

While the proposed exemption applied to all non-fossil 

fuels, most commenters focused on biomass-specific issues. Many 

commenters supported an exclusion for biomass-fired units that fire no more than 10 percent 

fossil fuels. Some commenters suggested that the exclusion for biomass-fired units should be raised 

to a 25 percent fossil fuel-use threshold. 

Many commenters supported the proposed 3-year averaging 

period for the fossil fuel-use criterion because it provides 

greater flexibility for operators to use fossil fuels when 

supply chains for the primary non-fossil fuels are disrupted, 

during unexpected malfunctions of the primary non-fossil fuel

handling systems, or when the unit’s maximum generating capacity 

is required by system operators for reliability reasons. Many 

commenters supported the 3-year averaging period because it is 

consistent with the final requirements under the EPA’s Mercury 

and Air Toxics Standards (MATS) and would allow non-fossil fuelfired units to use some fossil fuels for flame stabilization 
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without triggering applicability. Some commenters requested that 

the EPA clarify the method an operator should use during the 

first 3 years of operations to determine if a particular unit 

will meet the 10 percent fossil fuel-use threshold. Others asked 

whether or not an affected facility has a compliance obligation 

during the first 3-year period and, if an affected facility does 

not meet the 10 percent fossil fuel-use threshold during several 

12-month periods during the first 3 years, whether compliance 

calculations would be required for such 12-month periods. Other 

commenters had concerns with the 3-year averaging period,

stating that a source would no longer be subject to the NSPS if 

it fell below the threshold for any of the applicability metrics 

that the EPA proposed to calculate on a 3-year (or, in some 

cases, annual) basis. They argued that this would create a 

situation in which no one would know whether a particular plant 

will be subject to the standards until years after the emissions 

had already occurred. Some commenters were concerned that plants 

operating near the threshold could move in and out of the 

regulatory system, which would provide complications for 

compliance, enforcement, and permitting.

After considering these comments, the EPA has concluded 

that the proposed fossil fuel-use criterion based on the actual 

amount of fossil fuel burned is not an ideal approach to 

determine applicability. As commenters pointed out, facilities,
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permitting authorities, and the public would not know when 

construction is commenced whether a facility will be subject to 

the final NSPS, and after operation has commenced, a unit could 

move in and out of applicability each year. The intent of this 

rulemaking is to establish CO2 standards for fossil fuel-fired 

EGUs, not for non-fossil fuel-fired EGUs. Therefore, to simplify

compliance and establish CO2 standards for only those sources 

which we set out to regulate, we are finalizing a fossil fueluse criterion that will exempt dedicated non-fossil units. 

Specifically, units that are capable of burning 50 percent or 

more non-fossil fuel are exempt from the final standards so long 

as they are subject to a federally enforceable permit that 

limits their use of fossil fuels to 10 percent or less of their

heat input capacity on an annual basis. This approach 

establishes clear applicability criteria and avoids the prospect 

of units moving in and out of applicability based on their 

actual fuel use in a given year. Consistent with the 

applicability approach in the steam generating unit criteria 

pollutant NSPS, subpart Da, the final fossil fuel-use criterion

does not include “constructed for the purpose of” language. 

Therefore, an owner or operator could change a unit’s 

applicability in the future by seeking a modification of the 

unit’s permit conditions. A unit with the appropriate permit 

limitation will not be subject to the requirements in this 
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rulemaking. Similarly, an existing unit that takes a permit 

limitation restricting fossil-fuel use would no longer be an 

affected unit for the purposes of 111(d) state plans. This is 

consistent with our intent to reduce GHG emissions from fossil 

fuel-fired EGUs. 

We considered using either an annual or 3-year average for 

calculating compliance with the final fossil fuel-use criterion. 

Ultimately, we concluded that an annual average would provide 

sufficient flexibility for dedicated non-fossil units to combust 

fossil fuels for flame stabilization and other ancillary 

purposes, while maintaining consistency with the 12-month 

compliance periods used for most permit limitations. A 3-year 

average potentially would allow units to combust a significant 

quantity of fuels in a given year, leading to higher CO2

emissions, so long as they curtailed fossil-fuel use in a later 

year. This would defeat the purpose of the criterion, which is 

to exempt dedicated non-fossil units only. Finally, we are 

finalizing the 10 percent fossil-fuel use threshold in relation 

to a unit’s heat input capacity rather than its actual heat 

input, which is consistent with past approaches we have taken 

under the industrial boiler criteria pollutant NSPS. 

2. Industrial CHP Units

Another approach to generating electricity is the use of 

CHP units. A CHP unit can use a boiler, combustion turbine, 
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reciprocating engine, or various other generating technologies 

to generate electricity and useful thermal energy in a single, 

integrated system. CHP units are generally more efficient than 

conventional power plants because the heat that is normally 

wasted in a conventional power generation cooling system (e.g., 

cooling towers) is instead recovered as useful thermal output.

While the EPA did propose some applicability provisions specific 

to CHP units (e.g., subtract purchased power of adjacent 

facilities when determining total electric sales), in general,

the proposed applicability criteria for electric-only units and 

CHP units were similar. The intent of the proposed total and 

percentage electric sales criteria was to cover only utility CHP 

units, not industrial CHP units. To the extent that the 

proposal’s applicability provisions would have the effect of 

covering industrial CHP units, we solicited comment on an 

appropriate applicability exemption, and the criteria for that 

exemption, for highly efficient CHP facilities. 

Many commenters supported the exclusion of CHP units as a 

means of encouraging capital investments in highly efficient and 

reliable distributed generation technologies. These commenters

recommended that the EPA adopt an explicit exemption for CHP 

units at facilities that are classified as industrial (e.g., 

gas-fired CHPs within SIC codes 2911 – petroleum refining, 13 –

oil and gas extraction, and other industrial SIC codes as 
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appropriate). They also stated that the EPA should exclude CHP 

units that have an energy savings of 10 percent or more compared 

to separate heat and power. One commenter suggested that the 

final rule should cover only industrial-commercial-institutional 

CHP units that supply, on a net basis, more than two-thirds of 

their potential combined thermal and electric energy output and 

more than 450,000 MWh net-electric output to a utility power 

distribution system on an annual basis for five consecutive 

calendar years. The commenter also suggested that CHP units 

which have total thermal energy production that approaches or 

exceeds their total electricity production should be exempted.

Other commenters suggested exempting CHP units by fuel type 

or based on the definition of potential electric output. For 

example, some commenters suggested modifying the percentage 

electric sales threshold to be based on net system efficiency 

(including useful thermal output) rather than the rated netelectric-output efficiency. They also suggested that the 

applicability criteria should use a default efficiency of 50 

percent for CHP units. Some commenters suggested that a CHP unit

should not be considered an affected EGU if 20 percent or more 

of its total gross or net energy output consisted of useful 

thermal output on a 3-year rolling average basis. Other

commenters said that highly efficient CHP units that achieve an 
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overall efficiency level of 60 to 70 percent or higher should be 

excluded from applicability. 

The intent of this rulemaking is to cover only utility CHP 

units, because they serve essentially the same purpose as 

electric-only EGUs (i.e., the sale of electricity to the grid). 

Industrial CHP units, on the other hand, serve a different 

primary purpose (i.e., providing useful thermal output with 

electric sales as a by-product). With these facts in mind and 

after considering the comments, the EPA has concluded that it is 

appropriate to consider two factors for the final CHP exemption:

(1) whether the primary purpose of the CHP unit is to provide

useful thermal output rather than electricity and (2) whether 

the CHP unit is highly efficient and thus achieves environmental 

benefits.

We rejected many of the approaches suggested by the

commenters because they did not achieve one or both of the 

factors we identified. Specifically, the EPA has concluded that 

SIC code classification is not a sufficient indicator of the 

purpose (i.e., it does not correlate to useful thermal output) 

or environmental benefits (i.e., efficiency) of a unit. Further, 

an exemption based on SIC code could result in circumvention of 

the intended applicability. For example, this approach would 

allow a new EGU to locate near an industrial site, provide a 

trivial amount of useful thermal output to that site, sell 
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electricity to the grid, and nonetheless avoid applicability.

Similarly, increasing the electric sales criteria to two-thirds

of potential electric output and 450,000 MWh would essentially 

amount to a blanket exemption that tells us nothing about the 

primary purpose or efficiency of the unit. 

On the other hand, exemptions based on useful thermal 

output being greater than 20 percent of total output, thermal 

output being greater than electric output, or overall design 

efficiency value would identify whether the primary purpose of a 

unit is to generate thermal output, but they would not recognize 

the environmental benefits of highly efficient CHP units. While 

overall efficiency may appear to be a good indicator of 

environmental benefits, this is not always the case with CHP

units. Overall efficiency is a function of both efficient design 

and the power to heat ratio (the amount of electricity relative 

to the amount of useful thermal output). For example, boilerbased CHP units tend to produce large amounts of useful thermal 

output relative to electric output and tend to have high overall

efficiencies. For units producing primarily useful thermal 

output, the equivalent separate heat and power efficiency (i.e., 

the theoretical overall efficiency if the electricity and useful 

thermal output were produced by a stand-alone EGU and standalone boiler) would approach that of a stand-alone boiler (e.g., 

80 percent). However, combustion turbine-based CHP units tend to 
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produce relatively equal amounts of electricity and useful 

thermal output. In this case, the equivalent separate heat and 

power efficiency would be closer to 65 percent. Therefore, an 

exemption based on overall efficiency is not an indication of 

the fuel savings a CHP unit will achieve relative to separate 

heat and power. Further, this approach would encourage the 

development of CHP units that just meet the efficiency exemption 

criterion and would still cover many combustion turbine-based 

industrial CHP units. Conversely, while an exemption based on 

fuel savings relative to separate heat and power would recognize 

the environmental benefit of highly efficient CHP units, it 

would not consider the primary purpose of the CHP unit.

In the end, the EPA has concluded that maintaining the 

proposed percentage electric sales criterion with two 

adjustments addresses both factors with which we are concerned. 

First, we are changing the definition of “potential electric 

output” to be based on overall net efficiency at the maximum 

electric production rate, instead of just electric-only 

efficiency. Second, we are changing the percentage electric 

sales criterion to reflect the sliding scale, which is the 

overall design efficiency, calculated at the maximum useful 

thermal rating of the CHP unit (e.g., a CHP unit with a 

extraction condensing steam turbine would determine the 

efficiency at the maximum extraction/bypass rate), of the unit
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multiplied by the unit’s potential electric output instead of 

one-third of potential electric output as proposed. This 

approach recognizes the primary purpose of industrial CHP units

by providing a more generous percentage electric sales exemption 

to CHP units with high thermal output. As described previously, 

CHP units with high thermal loads tend to be more efficient and 

will therefore have a higher allowable percentage electric 

sales. By amending both the definition of “potential electric 

output” and the electric sales threshold, we assure that CHP 

units that primarily produce useful thermal output are exempted 

as industrial CHP units even if they are selling all of their 

electric output to the grid. As the relative amount of 

electricity generated by the CHP unit increases, efficiency will 

generally decrease, thus limiting allowable electric sales

before applicability is triggered. This approach also recognizes 

the environmental benefits of increased efficiency by 

encouraging industrial CHP units to be designed as efficiently 

as possible to take advantage of the higher electric sales 

permitted by the sliding scale.

In conclusion, a CHP unit will be an affected source unless 

it is subject to a federally enforceable permit that limits

annual total electric sales to less than or equal to the unit’s

design efficiency multiplied by its potential electric output or 
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219,000 MWh,

118 whichever is greater. This final applicability 

criterion will only cover CHP units that condense a significant

portion of steam generated by the unit and use the electric 

power generated as a result of condensing that steam to supply

electric power to the grid. CHP facilities that do not have a 

condensing steam turbine (e.g., combustion turbine-based CHP 

units without a steam turbine and boiler-based systems with a 

backpressure steam turbine) would generally not be physically 

capable of selling enough electricity to meet the applicability 

criterion, even if they sold 100 percent of the electricity 

generated and did not subtract out the electricity used by the 

thermal host(s). The EPA has concluded that this is appropriate 

because these sources are industrial by design and provide 

mostly useful thermal output. 

CHP facilities with a steam extraction condensing steam 

turbine will determine their potential electric output based on 

their efficiency on a net basis at the maximum electric 

production rate at the base load heat input rating (e.g., the 

CHP is condensing as much steam as possible to create 

electricity instead of using it for useful thermal output). We 

have concluded that it is necessary for CHP units with 

 

118 The EPA has concluded that it is appropriate to maintain the 

219,000 MWh total electric sales criterion for combustion 

turbine based CHP units to avoid potentially covering smaller 

industrial CHP units. 
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extraction condensing steam turbines to calculate their 

potential electric output at the maximum condensing level to 

avoid circumvention of the applicability criteria. For example, 

to avoid applicability a CHP unit could locate next to an 

industrial host and have the capability of selling significant 

quantities of useful thermal output without ever actually 

intending to supply much, if any, useful thermal output to the 

industrial host. If we calculated the potential electric output 

at the maximum level of thermal output, this type of CHP unit 

could operate at full condensing mode at base load conditions 

for the entire year and still not exceed the electric sales 

threshold. During the permitting process, the owner or operator 

will be able to determine if the unit is subject to the final 

standards in this rule. 

New EGUs with only limited useful thermal output will be 

subject to the final standards, but the vast majority of new CHP 

units will be classified as industrial CHP and will not be 

subject to the final standards. The EPA has concluded that this 

approach is similar to exempting CHP facilities that sell less 

than half of their total output (electricity plus thermal), but 

has the benefit of accounting for overall design efficiency. 

This approach both limits applicability to the industrial CHP 

units and encourages the installation of the most efficient CHP 

systems because more efficient designs will be able to have 
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higher permitted electric sales while not being subject to the 

CO2 standards included in this rulemaking.

3. Municipal Waste Combustors and Commercial and Industrial 

Solid Waste Incinerators

The purpose of this rulemaking is to establish CO2 standards 

for fossil fuel-fired EGUs. Municipal waste combustors and 

commercial and industrial solid waste incinerators typically 

have not been included in this source category. Therefore, even

if one of these types of units meets the general heat input and 

electric sales criteria, we are not finalizing CO2 emission 

standards for municipal waste combustors subject to subpart Eb 

of this part and commercial and industrial solid waste 

incinerators subject to subpart CCCC of this part. 

4. Certain Projects under Development

The EPA proposed that a limited class of projects under 

development should not be subject to the proposed standards. 

These were planned sources that may be capable of commencing

construction (within the meaning of section 111 (a)) shortly 

after the standard’s proposal date, and so would be classified 

as new sources, but which have a design which would be incapable 

of meeting the proposed standard of performance. See 79 FR 1461 

and CAA section 111 (a)(2). The EPA proposed that these sources 

would not be subject to the generally-applicable standard of 

performance, but rather would be subject to a unit-specific 
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permitting determination if and when construction actually 

commences. The EPA indicated that there could be three sources 

to which this approach could apply, and further indicated that 

the EPA could ultimately adopt the generally-applicable standard 

of performance for these sources (if actually constructed). 79 

FR 1461. 

As explained at Section III.J below, the EPA is finalizing 

this approach in this final rule. We again note that these 

sources, if and when constructed, could be ultimately subject to 

the 1,400 lb CO2/MWh-g standard, especially if there is no 

engineering basis, or demonstrated action in reliance, showing 

that the new source could not meet that standard.

E. Coal Refuse

In the April 2012 proposal, we solicited comment on 

subcategorizing and exempting EGUs that burn over 75 percent 

coal refuse on an annual basis. Multiple commenters supported 

the exemption, citing numerous environmental benefits of 

remediating coal refuse piles. Observing that coal refuse-fired 

EGUs typically use fluidized bed technologies, other commenters 

disagreed with any exemption, specifically citing the N2O 

emissions from fluidized bed boilers. In light of the 

environmental benefits of remediating coal refuse piles cited by 

commenters, the limited amount of coal refuse, and the fact that 

a new coal refuse-fired EGU would be located in close proximity 
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to the coal refuse pile, we sought additional comments regarding 

a subcategory for coal refuse-fired EGUs in the January 2014 

proposal. Specifically, we requested additional information on 

the net environmental benefits of coal refuse-fired EGUs and 

information to support an appropriate emissions standard for 

coal refuse-fired EGUs. One commenter on the April 2012 proposal 

stated that existing coal refuse piles are naturally combusting 

at a rate of 0.3 percent annually, and we requested comment on 

this rate and the proper approach to account for naturally 

occurring emissions from coal refuse piles in the January 2014 

proposal.

Commenters said that a performance standard is not feasible 

for coal refuse CFBs since there is no economically feasible way 

to capture CO2 through a conveyance designed and constructed to 

capture CO2. Commenters suggested that the EPA establish BSER for 

GHGs at modified coal refuse CFBs as a boiler tune-up that must 

be performed at least every 24 months. Commenters stated that 

the EPA should exempt coal refuse CFB units relative to their CO2

emissions to the extent that these units offset the uncontrolled 

ground level emissions from spontaneous combustion of legacy 

coal refuse stockpiles and noted that the mining of coal waste 

not only produces less emissions in the long term, but also 

helps to reclaim land that is currently used to store coal 

waste. In contrast, one commenter saw no legitimate basis for 
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coal refuse to be subcategorized and stated that it should be 

treated in the same manner as all other coal-fired EGUs. 

The EPA has concluded that an explicit exemption or 

subcategory specifically for coal refuse-fired EGUs is not 

appropriate. The costs faced by coal refuse facilities to 

install CCS are similar to coal-fired EGUs burning any of the 

primary coals, and the final applicable requirements and 

standards in the rule do not preclude the development of new 

coal refuse-fired units without CCS. Specifically, we are not 

finalizing CO2 standards for industrial CHP units. Many existing 

coal refuse-fired units are relatively small and designed as CHP 

units. Due to the expense of transporting coal refuse long 

distances, we anticipate that any new coal refuse-fired EGU

would be relatively small in size. Moreover, sites with 

sufficient thermal demand exist such that the unit could be 

designed as an industrial CHP facility and the requirements of 

this rule would not apply.

F. Format of the Output-based Standard

1. Net and Gross Output-based Standards

For all newly constructed units, the EPA proposed standards 

as gross output emission rates consistent with current 

monitoring and reporting requirements under 40 CFR part 75.119

 

119 79 FR 1447-48.
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For a non-CHP EGU, gross output is the electricity generation 

measured at the generator terminals. However, we solicited 

comment on finalizing equivalent net-output-based standards 

either as a compliance alternative or in lieu of the proposed 

gross-output-based standards. Net output is the gross electrical 

output less the unit’s total parasitic (i.e., auxiliary) power 

requirements. A parasitic load for an EGU is a load or device 

powered by electricity, steam, hot water, or directly by the 

gross output of the EGU that does not contribute electrical, 

mechanical, or useful thermal output. In general, parasitic 

energy demands include less than 7.5 percent of non-IGCC and 

non-CCS coal-fired station power output, approximately 15 

percent of non-CCS IGCC-based coal-fired station power output, 

and about 2.5 percent of non-CCS NGCC power output. The use of 

CCS increases both the electric and steam parasitic loads used 

internal to the unit, and these outputs are not considered when 

determining the emission rate. Net output is used to recognize 

the environmental benefits of: (1) EGU designs and control 

equipment that use less auxiliary power; (2) fuels that require 

less emissions control equipment; and (3) higher efficiency 

motors, pumps, and fans. For modified and reconstructed 

combustion turbines, the EPA also proposed standards as gross 

output emission rates, but solicited comment on finalizing net 

output standards. The rationale was that due to the low 
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auxiliary loads in non-CCS NGCC designs, the difference between 

a gross-output standard and a net-output standard has a limited 

impact on environmental performance. Auxiliary loads are more 

significant for modified and reconstructed boilers and IGCC 

units, and the EPA proposed standards on a net output basis for 

these units. The rationale included that this would enable 

owners/operators of these types of units to pursue projects that 

reduce auxiliary loads for compliance purposes. However, the EPA 

solicited comment on finalizing the standards on a gross-output 

basis. We also proposed to use either gross-output or net-output 

bases for each respective subcategory of EGUs (i.e., utility 

boilers, IGCC units, and combustion turbines) consistently 

across all CAA section 111(b) standards for new, modified, and 

reconstructed EGUs. 

Many commenters supported gross-output-based standards,

maintaining that a net-output standard penalizes the operation 

of air pollution control equipment. Several commenters disagreed 

with the agency's proposed rationale that a net-output standard 

would provide incentive to minimize auxiliary loads. The 

commenters believe utility commissions and existing economic 

forces already provide utilities with appropriate incentives to 

properly manage all of these factors. Some commenters supported 

a gross-output-based standard because variations in site 

conditions (e.g., available natural gas pressure, available 
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cooling water sources, and elevation) will likely penalize some 

owners and benefit others simply through variations in their 

particular plant-site conditions if a net basis is used. Several 

commenters stated that if the final rule includes a net-outputbased standard, it should be included as an option in 

conjunction with a gross-output-based option.

Several commenters opposed net-output-based standards 

because they believe it is difficult to accurately determine the 

net output of an EGU. They pointed out that many facilities have 

transformers that support multiple units at the facility, making 

unit-level reporting difficult. These commenters also stated 

that station electric services may come from outside sources to 

supply certain ancillary loads. One commenter stated that the 

benefit of switching to net-output-based standards would be 

small and would not justify the substantial complexities in both 

defining and implementing such a standard. Conversely, other 

commenters stated that net-metering is a well-established 

technology that should be required, particularly for newly 

constructed units. 

Other commenters, however, maintained that the final rule

should strictly require compliance on a net output-basis. They 

believe that this is the only way for the standards to minimize 

the carbon footprint of the electricity delivered to consumers.
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These commenters believe that, at a minimum, net-output-based 

standards should be included as an option in the final rule.

We are only finalizing gross-output-based standards for 

utility boilers and IGCC units. Providing an alternate netoutput-based standard that is based on gross-output-based 

emissions data and an assumed auxiliary load is most appropriate 

when the auxiliary load can be reasonably estimated and the 

choice between the net- and gross-output-based standard will not 

impact the identified BSER. For example, the auxiliary load for 

combustion turbines is relatively fixed and small, approximately 

2.5 percent, so the choice between a gross and net-output-based 

standard will not substantially impact technology choices. 

However, in the case of utility boilers, we have concluded that 

we do not have sufficient information to establish an 

appropriate net-output-based standard that would not impact the 

identified BSER for these types of units. The BSER for newly 

constructed steam generating units is based on the use of 

partial CCS. However, unlike the case for combustion turbines, 

owners/operators of utility boilers have multiple technology 

pathways available to comply with the actual emission standard. 

The choice of both control technologies and fuel impact the 

overall auxiliary load. For example, a coal-fired hybrid EGU 

(e.g., one that includes integrated solar thermal equipment for 

feedwater heating or steam augmentation) or a coal-fired EGU co-
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firing natural gas would have lower non-CCS related auxiliary 

loads and, because the amount of CCS needed to comply with the 

standard would also be smaller, the CCS auxiliary loads would 

also be reduced. Therefore, we cannot identify an appropriate 

assumed auxiliary load to establish an equivalent net-outputbased standard. In addition, many IGCC facilities (which could 

be used as an alternative technology for complying with the 

standard of performance; see Sections IV.B and V.P below) have 

been proposed or are envisioned as co-production facilities 

(i.e., to produce useful by-products and chemicals along with 

electricity). As noted in the proposal, we have concluded that 

predicting the net electricity at these co-production facilities 

would be more challenging to implement under these 

circumstances.

In contrast, based on further evaluation and review of 

issues raised by commenters, the EPA is finalizing the CO2

standard for combustion turbine EGUs in a format that is similar 

to the current NSPS format for criteria pollutants. The default 

final standards establish a gross-output-based standard. This 

allows owners/operators of new combustion turbines to comply 

with the CO2 emissions standard under Part 60 using the same data 
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currently collected under Part 75.120 However, many permitting 

authorities commented persuasively that the environmental 

benefits of using net-output-based standards can outweigh any 

additional complexities for particular units, and have indeed 

adopted net-output standards in recent GHG operating permits for 

combustion turbines. We expect this trend to continue and have 

concluded that it is appropriate to support the expanded use of 

net-output-based standards, and therefore are allowing certain 

sources to elect between gross output-based and net-output-based 

standards. Only combustion turbines are eligible to make this 

election.

The rule specifies an alternative net-output-based standard 

of 1,030 lb CO2/MWh-n for combustion turbines. This standard is 

equivalent to the otherwise-applicable gross-output-based 

standard of 1,000 lb CO2/MWh-g.121

The procedures for requesting this alternative net-outputbased standard require the owner or operator to petition the 

Administrator in writing to comply with the alternate applicable 

net-output-based standard. If the Administrator grants the 

 

120 Additionally, having an NSPS standard that is measured using 

the same monitoring equipment as required under the operating 

permit minimizes compliance burden. If a combustion turbine were 

subject to both a gross and net emission limit, more expensive 

higher accuracy monitoring could be required for both 

measurements.

121 Assuming a 3 percent auxiliary load for the NGCC system.
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petition, this election would be binding and would be the unit’s

sole means of demonstrating compliance. Owners or operators 

complying with the net-output-based standard must similarly

petition the Administrator to switch back to complying with the 

gross-output-based standard.

2. Useful Thermal Output

For CHP units, useful thermal output is also used when 

determining the emission rate. Previous rulemakings issued by 

the EPA have prescribed various “discount factors” of the 

measured useful thermal output to be used when determining the 

emission rate. We proposed that 75 percent credit is the 

appropriate discount factor for useful thermal output, and we 

solicited comment on a range from two-thirds to three-fourths 

credit for useful thermal output in the proposal for newly 

constructed units and two-thirds to one hundred percent credit 

in the proposal for modified and reconstructed units. The 75 

percent credit was based on matching the emission rate, but not 

the overall emissions, of a hypothetical CHP unit to the 

proposed emission rate.

Many commenters said that in order to fully account for the 

environmental benefits of CHP and to reflect the environmental 

benefits of CHP, the EPA should allow 100 percent of the useful

thermal output from CHP units. Commenters noted that providing 

100 percent credit for useful thermal output is consistent with 
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the past practice of the EPA in the stationary combustion 

turbine criteria pollutant NSPS and state approaches for 

determining emission rates for CHP units. 

Based on further consideration and review of the comments 

submitted, we are finalizing 100 percent credit for useful 

thermal output for all newly constructed, modified, and 

reconstructed CHP sources. We have concluded that this is 

appropriate because, at the same reported emission rate, a 

hypothetical CHP unit would have the same overall GHG emissions 

as the combined emission rate of separate heat and power 

facilities. Any discounting of useful thermal output could 

distort the market and discourage the development of new CHP 

units. Full credit for useful thermal output appropriately 

recognizes the environmental benefit of CHP.

G. CO2 Emissions Only

The air pollutant regulated in this final action is 

greenhouse gases. However, the standards in this rule are 

expressed in the form of limits on only emissions of CO2, and not 

the other constituent gases of the air pollutant GHGs.122 We are 

not establishing a limit on aggregate GHGs or separate emission 

 

122 As noted above, in the Endangerment Finding, the EPA defined 

the relevant “air pollution” as the atmospheric mix of six longlived and directly-emitted greenhouse gases: carbon dioxide 

(CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons 

(HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6). 

74 FR 66497.
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limits for other GHGs (such as methane (CH4) or nitrous oxide 

(N2O)) as other GHGs represent less than 1 percent of total 

estimated GHG emissions (as CO2e) from fossil fuel-fired electric 

power generating units.123 Notwithstanding this form of the 

standard, consistent with other EPA regulations addressing GHGs, 

the air pollutant regulated in this rule is GHGs.

124

H. Legal Requirements for Establishing Emission Standards 

1. Introduction

In the January 2014 proposal, we described the principal 

legal requirement for standards of performance under CAA section 

111(b), which is that the standards of performance must consist 

of standards for emissions that reflect the degree of emission 

limitation achievable though the application of the “best system 

of emission reduction ... adequately demonstrated,” taking into 

account cost and any non-air quality health and environment 

impact and energy requirements. We noted that the D.C. Circuit 

has handed down numerous decisions that interpret this CAA 

provision, including its component elements, and we reviewed 

that case law in detail.125

We received comments on our proposed interpretation, and in 

light of those comments, in this rule, we are clarifying our 

 

123 EPA Greenhouse Gas Reporting Program; 

www.epa.gov/ghgreporting/.

124 See 77 FR 31257-30 (June 3, 2010).

125 79 FR 1430, 1462 (January 8, 2014).
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interpretation in certain respects. We discuss our 

interpretation below.126

2. CAA Requirements and Court Interpretation

As noted above, the CAA section 111 requirements that 

govern this rule are as follows: As the first step towards 

establishing standards of performance, the EPA “shall publish . 

. . a list of categories of stationary sources . . . [that] 

cause[], or contribute[] significantly to, air pollution which 

may reasonably be anticipated to endanger public health or 

welfare.” CAA section 111(b)(1)(A). Following that listing, the 

EPA “shall publish proposed regulations, establishing federal 

standards of performance for new sources within such category” 

and then “promulgate . . . such standards” within a year after 

proposal. CAA section 111(b)(1)(B). The EPA “may distinguish 

among classes, types, and sizes within categories of new sources 

for the purpose of establishing such standards.” CAA section

111(b)(2). The term “standard of performance” is defined to 

 

126 We also discuss our interpretation of the requirements for 

standards of performance and the BSER under section 111(d), for 

existing sources, in the section 111(d) rulemaking that the EPA 

is finalizing with this rule. Our interpretations and 

applications of these requirements in the two rulemakings are 

generally consistent with each other except to the extent that 

they reflect distinctions between new and existing sources. For 

example, the BSER for new industrial facilities, which are

expected to have lengthy useful lives, should include, at a 

minimum, the most advanced pollution controls available, but for 

existing sources, the additional costs of retrofit may render 

those controls too expensive.
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“mean[] a standard for emissions of air pollutants which 

reflects the degree of emission limitation achievable through 

the application of the best system of emission reduction which 

(taking into account the cost of achieving such reduction and 

any non-air quality health and environmental impact and energy 

requirements) the Administrator determines has been adequately 

demonstrated.” CAA section 111(a)(1).

As noted in the January 2014 proposal, Congress first 

included the definition of “standard of performance” when 

enacting CAA section 111 in the 1970 Clean Air Act Amendments 

(CAAA), amended it in the 1977 CAAA, and then amended it again 

in the 1990 CAAA to largely restore the definition as it read in 

the 1970 CAAA. It is in the legislative history for the 1970 and 

1977 CAAAs that Congress primarily addressed the definition as 

it read at those times, and that legislative history provides 

guidance in interpreting this provision.127 In addition, the D.C. 

 

127 In the 1970 CAAA, Congress defined “standard of performance,” 

under §111(a)(1), as—

a standard for emissions of air pollutants which 

reflects the degree of emission limitation achievable 

through the application of the best system of emission 

reduction which (taking into account the cost of 

achieving such reduction) the Administrator determines 

has been adequately demonstrated.

In the 1977 CAAA, Congress revised the definition to 

distinguish among different types of sources, and to require 

that for fossil fuel-fired sources, the standard: (i) be based 
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Circuit has reviewed rulemakings under CAA section 111 on 

numerous occasions during the past 40 years, handing down 

decisions dated from 1973 to 2011,128 through which the Court has 

developed a body of case law that interprets the term “standard 

of performance.”

3. Key Elements of Interpretation

By its terms, the definition of “standard of performance” 

under CAA section 111(a)(1) provides that the emission limits 

 

on, in lieu of the “best system of emission reduction . . .

adequately demonstrated,” the “best technological system of 

continuous emission reduction . . . adequately demonstrated;” 

and (ii) require a percentage reduction in emissions. In 

addition, in the 1977 CAAA, Congress expanded the parenthetical 

requirement that the Administrator consider the cost of 

achieving the reduction to also require the Administrator to 

consider “any nonair quality health and environment impact and 

energy requirements.”

In the 1990 CAAA, Congress again revised the definition, 

this time repealing the requirements that the standard of 

performance be based on the best technological system and 

achieve a percentage reduction in emissions, and replacing those 

provisions with the terms used in the 1970 CAAA version of 

§111(a)(1) that the standard of performance be based on the 

“best system of emission reduction . . . adequately 

demonstrated.” This 1990 CAAA version is the current 

definition. Even so, because parts of the definition as it read 

under the 1977 CAAA were retained in the 1990 CAAA, the 

explanation in the 1977 CAAA legislative history, and the 

interpretation in the case law, of those parts of the definition 

in the case law remain relevant to the definition as it reads 

today.

128 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 

1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, (D.C. 

Cir. 1973); Portland Cement Ass’n v. EPA, 665 F.3d 177 (D.C. 

Cir. 2011). See also Delaware v. EPA, No. 13-1093 (D.C. Cir. May 

1, 2015).
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that the EPA promulgates must be “achievable” by application of 

a “system of emission reduction” that the EPA determines to be 

the “best” that is “adequately demonstrated,” “taking into 

account ... cost ... nonair quality health and environmental impact 

and energy requirements.” The D.C. Circuit has stated that, in 

determining the “best” system, the EPA must also take into 

account “the amount of air pollution”129 reduced and the role of

“technological innovation.”130 The Court has emphasized that the 

EPA has discretion in weighing those various factors.131,132

Our overall approach to determining the BSER, which 

incorporates the various elements, is as follows: First, the EPA

identifies the “system[s] of emission reduction” that have been 

“adequately demonstrated” for a particular source category. 

Second, the EPA determines the “best” of these systems after 

evaluating extent of emission reductions, costs, any non-air

health and environmental impacts, and energy requirements. And 

 

129 See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 

1981). 

130 See Sierra Club v. Costle, 657 F.2d at 347.

131 See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 

Cir. 1999).

132 Although section 111(a)(1) may be read to state that the 

factors enumerated in the parenthetical are part of the 

“adequately demonstrated” determination, the D.C. Circuit’s case

law appears to treat them as part of the “best” determination. 

See Sierra Club v. Costle, 657 F.2d at 325-26. It does not 

appear that those two approaches would lead to different 

outcomes. In this rule, the EPA is following the D.C. Circuit 

case law and treating the factors as part of the “best” 

determination. 
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third, the EPA selects an achievable standard for emissions -

here, the emission rate - based on the performance of the BSER. 

The remainder of this subsection discusses the various elements 

in that analytical approach.

a. “System[s] of emission reduction ... adequately demonstrated” 

The EPA’s first step is to identify “system[s] of emission 

reduction ... adequately demonstrated.” For the reasons 

discussed below, for the various types of newly constructed, 

modified, and reconstructed sources in this rulemaking, the EPA 

focused on efficient generation, add-on controls, efficiency 

improvements, and clean fuels as the systems of emission 

reduction. 

An “adequately demonstrated” system, according to the D.C. 

Circuit, is “one which has been shown to be reasonably reliable, 

reasonably efficient, and which can reasonably be expected to 

serve the interests of pollution control without becoming 

exorbitantly costly in an economic or environmental way.”134 It 

does not mean that the system “must be in actual routine use 

somewhere.”135 Rather, the Court has said, “[t]he Administrator 

may make a projection based on existing technology, though that 

 

134 Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. 

Cir. 1973), cert. denied, 416 U.S. 969 (1974).

135 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973) (citations omitted) (discussing the Senate and House 

bills and reports from which the language in CAA section 111 

grew).
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projection is subject to the restraints of reasonableness and 

cannot be based on ‘crystal ball’ inquiry.”136 Similarly, the EPA 

may “hold the industry to a standard of improved design and 

operational advances, so long as there is substantial evidence 

that such improvements are feasible.”137 Ultimately, the analysis 

“is partially dependent on ‘lead time,’” that is, “the time in 

which the technology will have to be available.”138 Per CAA 

section 111(e), standards of performance under CAA section 

111(b) are applicable immediately after the effective date of 

their promulgation 

(1) Technical feasibility of the best system of emission 

reduction

As the January 2014 proposal indicates, the requirement 

that the standard for emissions be “achievable” based on the 

“best system of emission reduction ... adequately demonstrated” 

indicates that one of the requirements for the technology or 

other measures that the EPA identifies as the BSER is that the 

measure must be technically feasible. See 79 FR 1430, 1463 

(January 8, 2014). 

 

136 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973) (citations omitted).

137 Sierra Club v. Costle, 657 F.2d 298, 364 (1981).

138 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973) (citations omitted).
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b. “Best”

In determining which adequately demonstrated system of 

emission reduction is the “best,” the EPA considers the 

following factors:

(1) Costs

Under CAA section 111(a)(1), the EPA is required to take 

into account “the cost of achieving” the required emission 

reductions. As described in the January 2014 proposal,140 in 

several cases the D.C. Circuit has elaborated on this cost 

factor and formulated the cost standard in various ways, stating 

that the EPA may not adopt a standard the cost of which would be 

“exorbitant,”141 “greater than the industry could bear and 

survive,”142 “excessive,”143 or “unreasonable.”144 For convenience,

in this rulemaking, we use ‘reasonableness’ to describe costs 

well within the bounds established by this jurisprudence.

145 

 

140 79 FR 1464 (January 8, 2014).

141 Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 

1999).

142 Portland Cement Ass’n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 

1975).

143 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).

144 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).

145 These cost formulations are consistent with the legislative 

history of section 111. The 1977 House Committee Report noted:

In the [1970] Congress [sic: Congress’s] view, it was 

only right that the costs of applying best practicable 

control technology be considered by the owner of a 

large new source of pollution as a normal and proper 

expense of doing business.
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The D.C. Circuit has indicated that the EPA has substantial 

discretion in its consideration of cost under section 111(a). In 

several cases, the Court upheld standards that entailed 

significant costs, consistent with Congress’s view that “the 

costs of applying best practicable control technology be 

considered by the owner of a large new source of pollution as a 

normal and proper expense of doing business.”

146 See Essex 

Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir. 

 

1977 House Committee Report at 184. Similarly, the 1970 Senate 

Committee Report stated:

The implicit consideration of economic factors in 

determining whether technology is “available” should 

not affect the usefulness of this section. The 

overriding purpose of this section would be to prevent 

new air pollution problems, and toward that end, 

maximum feasible control of new sources at the time of 

their construction is seen by the committee as the 

most effective and, in the long run, the least 

expensive approach.

S. Comm. Rep. No. 91-1196 at 16. Some commenters asserted that 

we do not have authority to revise the cost standard as 

established in the case law, e.g., “exorbitant,” “excessive,” 

etc., to a “reasonableness” standard that may be considered less 

protective of the environment. We agree that we do not have 

authority to revise the cost standard as established in the case 

law, and we are not attempting to do so here. Rather, our 

description of the cost standard as “reasonableness” is intended 

to be a convenient term for referring to the cost standard as 

established in the case law.

146 1977 House Committee Report at 184.
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1973);147 Portland Cement Association v. Ruckelshaus, 486 F.2d 

375, 387-88 (D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 

298, 313 (D.C. Cir. 1981) (upholding standard imposing controls 

on SO2 emissions from coal-fired power plants when the ”cost of 

the new controls ... is substantial”).

148 Moreover, section 

111(a) does not provide specific direction regarding what metric 

or metrics to use in considering costs, again affording the EPA 

considerable discretion in choosing a means of cost 

consideration.149

As discussed below, the EPA may consider costs on both a 

source-specific basis and a sector-wide, regional, or nationwide 

basis. The EPA is finding here that whether costs are considered 

on a source-specific basis, an industry/national basis, or both, 

they are reasonable. See Sections V.H and I below.

(2) Non-air quality health and environmental impacts

 

147 The costs for these standards were described in the 

rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 

5769 (March 21, 1972).

148 Indeed, in upholding the EPA’s consideration of costs under 

the provisions of the Clean Water Act authorizing technologybased standards based on performance of a best technology taking 

costs into account, courts have also noted the substantial 

discretion delegated to the EPA to weigh cost considerations 

with other factors. Chemical Mfr’s Ass’n v. EPA, 870 F.2d 177, 

251 (5th Cir. 1989); Association of Iron and Steel Inst. v. EPA, 

526 F.2d 1027, 1054 (3d Cir. 1975); Ass’n of Pacific Fisheries 

v. EPA, 615 F.2d 794, 808 (9th Cir. 1980).

149 See, e.g., Husqvarna AB v. EPA, 254 F.3d 195, 200 (D.C. Cir. 

2001) (where CAA section 213 does not mandate a specific method 

of cost analysis, the EPA may make a reasoned choice as to how 

to analyze costs).
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Under CAA section 111(a)(1), the EPA is required to take 

into account “any nonair quality health and environmental 

impact” in determining the BSER. As the D.C. Circuit has 

explained, this requirement makes explicit that a system cannot 

be “best” if it does more harm than good due to cross-media 

environmental impacts.150 The EPA has carefully considered such 

cross-media impacts here, in particular potential impacts to 

underground sources of drinking water posed by CO2 sequestration, 

and water use necessary to operate carbon capture systems. See 

Sections V.N and O below.

(3) Energy considerations

Under CAA section 111(a)(1), the EPA is required to take 

into account “energy requirements.” As discussed below, the EPA 

may consider energy requirements on both a source-specific basis 

and a sector-wide, region-wide, or nationwide basis. Considered 

on a source-specific basis, “energy requirements” entail, for 

example, the impact, if any, of the system of emission reduction 

on the source’s own energy needs. In this rulemaking, as 

discussed below in Section V.O.3, the EPA considered the 

parasitic load requirements of partial CCS. The EPA is finding 

here that whether energy requirements are considered on a 

 

150 Portland Cement v. EPA, 486 F. 2d at 384; Sierra Club v. 

Costle, 657 F.2d at 331; see also Essex Chemical Corp. v. 

Ruckelshaus, 486 F.2d at 439 (remanding standard to consider 

solid waste disposal implications of the BSER determination).
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source-specific basis, an industry/national basis, or both, they 

are reasonable. See Sections V.O.3 and XIII.C.

(4) Amount of emissions reductions

At proposal, we noted that although the definition of 

“standard of performance” does not by its terms identify the 

amount of emissions from the category of sources or the amount 

of emission reductions achieved as factors the EPA must consider 

in determining the “best system of emission reduction,” the D.C. 

Circuit has stated that the EPA must in fact do so. See Sierra 

Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981) (“we can 

think of no sensible interpretation of the statutory words “best 

... system” which would not incorporate the amount of air 

pollution as a relevant factor to be weighed when determining 

the optimal standard for controlling ... emissions”).151 The fact 

that the purpose of a “system of emission reduction” is to 

reduce emissions, and that the term itself explicitly 

incorporates the concept of reducing emissions, supports the 

Court’s view that in determining whether a “system of emission 

 

151 Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was 

governed by the 1977 CAAA version of the definition of “standard 

of performance,” which revised the phrase “best system” to read, 

“best technological system.” As noted above, the 1990 CAAA 

deleted “technological,” and thereby returned the phrase to how 

it read under the 1970 CAAA. The court’s interpretation of this 

phrase in Sierra Club v. Costle to require consideration of the 

amount of air emissions reductions remains valid for the phrase 

“best system.”
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reduction” is the “best,” the EPA must consider the amount of 

emission reductions that the system would yield.152 Even if the 

EPA were not required to consider the amount of emission 

reductions, the EPA has the discretion to do so, on grounds that 

either the term “system of emission reduction” or the term 

“best” may reasonably be read to allow that discretion.

(5) Sector or nationwide component of the BSER factors

As discussed in the January 2014 proposal, another 

component of the D.C. Circuit’s interpretations of CAA section 

111 is that the EPA may consider the various factors it is 

required to consider on a national or regional level and over 

time, and not only on a plant-specific level at the time of the 

rulemaking.153 The D.C. Circuit based this conclusion on a review 

of the legislative history, stating, 

The Conferees defined the best technology in 

terms of “long-term growth,” “long-term cost savings,” 

effects on the “coal market,” including prices and 

utilization of coal reserves, and “incentives for 

improved technology.” Indeed, the Reports from both 

Houses on the Senate and House bills illustrate very 

clearly that Congress itself was using a long-term 

lens with a broad focus on future costs, environmental 

and energy effects of different technological systems 

 

152 See also NRDC v. EPA, 479 F. 3d 875, 880 (D.C. Cir. 2006) 

(“best performing” source for purposes of CAA section 112 (d)(3) 

is source with the lowest emission levels).

153 79 FR 1430, 1465 January 8, 2014) (citing Sierra Club v. 

Costle, 657 F.2d at 351).
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when it discussed section 111.154

The Court has upheld rules that the EPA “justified ... in 

terms of the policies of the Act,” including balancing long-term 

national and regional impacts:

The standard reflects a balance in environmental, 

economic, and energy consideration by being 

sufficiently stringent to bring about substantial 

reductions in SO2 emissions (3 million tons in 1995) 

yet does so at reasonable costs without significant 

energy penalties.... By achieving a balanced coal 

demand within the utility sector and by promoting the 

development of less expensive SO2 control technology, 

the final standard will expand environmentally 

acceptable energy supplies to existing power plants 

and industrial sources.

By substantially reducing SO2 emissions, the 

standard will enhance the potential for long term 

economic growth at both the national and regional 

levels.155

Some commenters objected that this case law did not allow 

the EPA to ignore source-specific impacts (particularly cost 

impacts) by basing determinations solely on impacts at a 

regional or national level. In fact, the EPA’s consideration of 

cost, non-air quality impacts, and energy requirements reflect 

source-specific impacts, as well as (for some considerations) 

impacts that are sector-wide, regional, or national. See Section 

 

154 Sierra Club v. Costle, 657 F.2d at 331 (citations omitted) 

(citing legislative history).

155 Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 FR

33583/3 - 33584/1). In the January 2014 proposal, we explained 

that although the D.C. Circuit decided Sierra Club v. Costle

before the Chevron case was decided in 1984, the D.C. Circuit’s 

decision could be justified under either Chevron step 1 or 2. 79 

FR 1430, 1466 (January 8, 2014).
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V.H.6 below.

c. Achievability of the Standard for Emissions

In the January 2014 proposal, the EPA recognized that the 

first element of the definition of “standard of performance” is 

that “the emission limit [i.e., the ‘standard for emissions’] 

that the EPA promulgates must be ‘achievable’” based on 

performance of the BSER. 79 FR 1430, 1463 (January 8, 2014). 

According to the D.C. Circuit, a standard for emissions is 

“achievable” if a technology can reasonably be projected to be 

available to new sources at the time they are constructed that 

will allow them to meet the standard.156 Moreover, according to 

the Court, ”[a]n achievable standard is one which is within the 

realm of the adequately demonstrated system’s efficiency and 

which, while not at a level that is purely theoretical or 

experimental, need not necessarily be routinely achieved within 

the industry prior to its adoption.”157 To be achievable, a 

standard “must be capable of being met under most adverse 

conditions which can reasonably be expected to recur and which 

 

156 Portland Cement, 486 F.2d at 391-92. Some commenters stated 

that the EPA’s analysis of the requirements for “standard of 

performance,” including the BSER, attempted to eliminate the 

requirement that the standard for emissions must be 

“achievable.” We disagree with this comment. As just quoted, the 

EPA’s analysis recognizes that the standard for emissions must 

be achievable through the application of the BSER.

157 Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 (D.C. 

Cir. 1973), cert. denied, 416 U.S. 969 (1974).
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are not or cannot be taken into account in determining the ‘cost 

of compliance.’”158 To show that a standard is achievable, the 

EPA must “(1) identify variable conditions that might contribute 

to the amount of expected emissions, and (2) establish that the 

test data relied on by the agency are representative of 

potential industry-wide performance, given the range of 

variables that affect the achievability of the standard.”159

In Sections V.J and IX.D below, we show both that the BSER 

for new steam generating units and combustion turbines is 

technically feasible and adequately demonstrated, and that the 

standards of 1,400 lb CO2/MWh-g and 1,000 lb CO2/MWh-g are

achievable considering the range of operating variables that 

affect achievability.

d. Expanded Use and Development of Technology

In the January 2014 proposal, we noted that the D.C. 

Circuit has made clear that Congress intended for CAA section 

111 to create incentives for new technology and therefore that 

 

158 Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 433, n.46 (D.C. Cir. 

1980).

159 Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981) 

(citing Nat’l Lime Ass’n v. EPA, 627 F.2d 416 (D.C. Cir. 1980). 

In considering the representativeness of the source tested, the 

EPA may consider such variables as the “‘feedstock, operation, 

size and age’ of the source.” Nat’l Lime Ass’n v. EPA, 627 F.2d 

416, 433 (D.C. Cir. 1980). Moreover, it may be sufficient to 

“generalize from a sample of one when one is the only available 

sample, or when that one is shown to be representative of the 

regulated industry along relevant parameters.” Nat’l Lime Ass’n 

v. EPA, 627 F.2d 416, 434, n.52 (D.C. Cir. 1980).
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the EPA is required to consider technological innovation as one 

of the factors in determining the “best system of emission 

reduction.”160

The Court grounded its reading in the statutory text.161 In 

addition, in the January 2014 proposal, we noted that the 

Court’s interpretation finds additional support in the 

legislative history.

162 We also explained that the legislative 

history identifies three different ways that Congress designed 

CAA section 111 to authorize standards of performance that 

promote technological improvement: (i) the development of 

technology that may be treated as the “best system of emission 

reduction . . . adequately demonstrated” under section 

111(a)(1); (ii) the expanded use of the best demonstrated 

 

160 See 79 FR 1430, 1465 (January 8, 2014), Sierra Club v. 

Costle, 657 F.2d at 346-47.

161 Sierra Club v. Costle, 657 F. 2d at 346 (“Our interpretation 

of section 111(a) is that the mandated balancing of cost, 

energy, and nonair quality health and environmental factors 

embraces consideration of technological innovation as part of 

that balance. The statutory factors which the EPA must weigh are 

broadly defined and include within their ambit subfactors such 

as technological innovation.”).

162 See 79 FR 1430, 1465 (January 8, 2014) (citing S.Rep. 91-1196 

at 16 (1970)) (“Standards of performance should provide an 

incentive for industries to work toward constant improvement in 

techniques for preventing and controlling emissions from 

stationary sources”); S. Rep. 95-127 at 17 (1977) (cited in 

Sierra Club v. Costle, 657 F.2d at 346 n. 174) (“The section 111 

Standards of Performance ... sought to assure the use of 

available technology and to stimulate the development of new 

technology”).
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technology; and (iii) the development of emerging technology.163

Even if the EPA were not required to consider technological 

innovation as part of its determination of the BSER, it would be 

reasonable for the EPA to consider it, either because 

technological innovation may be considered an element of the 

term “best,” or because the term “best system of emission 

reduction” is ambiguous as to whether technological innovation 

may be considered. The interpretation is likewise consistent 

with the evident purpose of section 111(b) to require new 

sources to maximize emission reductions using state-of-the-art 

means of control.

Commenters stated that the requirement to consider 

technological innovation does not authorize the EPA to identify 

as the BSER a technology that is not adequately demonstrated. 

The proposal did not, and we do not in this final rule, claim to 

the contrary. In any event, as discussed below, the EPA may 

justify the control technologies identified in this rule as the 

BSER even without considering the factor of incentivizing 

technological innovation or development. 

e. Agency Discretion

As discussed in the January 2014 proposal, the D.C. Circuit 

has made clear that the EPA has broad discretion in determining 

 

163 79 FR 1465 (citing case law and legislative history).
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the appropriate standard of performance under the definition in 

CAA section 111(a)(1), quoted above. Specifically, in Sierra 

Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981), the Court 

explained that “section 111(a) explicitly instructs the EPA to 

balance multiple concerns when promulgating a NSPS,”164 and 

emphasized that “[t]he text gives the EPA broad discretion to 

weigh different factors in setting the standard.”165 In Lignite 

Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999), the Court 

reiterated:

Because section 111 does not set forth the weight 

that should be assigned to each of these factors, we 

have granted the agency a great degree of discretion 

in balancing them.... EPA's choice [of the ‘best 

system’] will be sustained unless the environmental or 

economic costs of using the technology are 

exorbitant.... EPA [has] considerable discretion under 

section 111.166

 

164 Sierra Club v. Costle, 657 F.2d at 319. 

165 Sierra Club v. Costle, 657 F.2d at 321; see also New York v. 

Reilly, 969 F. 2d at 1150 (because Congress did not assign the 

specific weight the Administrator should assign to the statutory 

elements, “the Administrator is free to exercise [her] 

discretion” in promulgating an NSPS).

166

Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 

1999) (paragraphing revised for convenience). See also NRDC v. 

EPA, 25 F.3d 1063, 1071 (D.C. Cir. 1994) (The EPA did not err in 

its final balancing because “neither RCRA nor EPA’s regulations 

purports to assign any particular weight to the factors listed 

in subsection (a)(3). That being the case, the Administrator 

was free to emphasize or deemphasize particular factors, 

constrained only by the requirements of reasoned agency decision

making.”).
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f. Lack of Requirement that Standard Must Be Met by All Sources

In the January 2014 proposal, the EPA proposed that, under 

CAA section 111, an emissions standard may meet the requirements 

of a “standard of performance” even if it cannot be met by every 

new source in the source category that would have constructed in 

the absence of that standard. As described in the January 2014 

proposal, the EPA based this view on (i) the legislative history 

of CAA section 111, read in conjunction with the legislative 

history of the CAA as a whole; (ii) case law under analogous CAA 

provisions; and (iii) long-standing precedent in the EPA 

rulemakings under CAA section 111.167

Commenters contested this assertion, arguing that a 111(b) 

standard must be achievable by all new sources. We continue to 

take the same position as at proposal for the reasons described 

there. We note that as a practical matter, in this rulemaking, 

the issue of whether all new steam-generating sources can 

implement partial-capture CCS is largely dependent on the 

geographic scope of geologic sequestration sites. As discussed 

below in Section V.M, geologic sequestration sites are widely 

available, and a steam-generating plant with partial CCS that is 

sited near an area that is suitable for geologic sequestration

can serve demand in a large area that may not have sequestration 

 

167 79 FR 1430, 1466 (January 8, 2014).
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sites available. In any event, the standard of 1,400 lb CO2/MW-g

that we promulgate in this final rule can be achieved by new 

steam generating EGUs – including new utility boilers and IGCC 

units - through co-firing with natural gas in lieu of installing 

partial CCS, which moots the issue of the geographic 

availability of geologic sequestration. 

g. EPAct05

The Energy Policy Act of 2005 (“EPAct05”) authorizes 

assistance in the form of grants, loan guarantees, as well as 

federal tax credits for investment in “clean coal technology.”

Sections 402(i), 421(a), and 1307(b) (adding section 48A(g) to 

the Internal Revenue Code (“IRC”)) address the extent to which 

information from clean coal projects receiving assistance under 

the EPAct05 may be considered by the EPA in determining what is 

the best system of emission reduction adequately

demonstrated. Section 402(i) of the EPAct05 limits the use of 

information from facilities that receive assistance under 

EPAct05 in CAA section 111 rulemakings:

“No technology, or level of emission reduction, solely by 

reason of the use of the technology, or the achievement of the 

emission reduction, by 1 or more facilities receiving assistance 

under this Act, shall be considered to be adequately 
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demonstrated [] for purposes of section 111 of the Clean Air Act 

....”

168

IRC section 48A(g) contains a similar constraint concerning 

the use of technology or level of emission reduction from EGU

facilities for which a tax credit is allowed:

“No use of technology (or level of emission reduction 

solely by reason of the use of the technology), and no 

achievement of any emission reduction by the 

demonstration of any technology or performance level, 

by or at one or more facilities with respect to which 

a credit is allowed under this section, shall be 

considered to indicate that the technology or 

performance level is adequately demonstrated [] for 

purposes of section 111 of the Clean Air Act ....” 

The EPA specifically solicited comment on its 

interpretation of these provisions. 79 FR 10750 (Feb. 26, 

2014)(Notice of Data Availability). With respect to EPAct05 

sections 402(i) and 421(a), the EPA proposed that these 

provisions barred consideration where EPAct05-assisted

facilities were the sole support for the BSER determination, but 

that these sources could support a BSER determination so long as 

there is additional evidence supporting the determination.169 In 

 

168 Codified at 42 U.S.C. 15962(a). EPAct05 section 421(a) 

similarly states: “No technology, or level of emission 

reduction, shall be treated as adequately demonstrated for 

purpose [sic] of section 7411 of this title, ... solely by reason 

of the use of such technology, or the achievement of such

emission reduction, by one or more facilities receiving 

assistance under section 13572(a)(1) of this title”.

169 Technical Support Document p. 6.
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addition, the EPA viewed the two prohibitions as relating only 

to the technology or emissions reduction for which assistance 

was given.170 The EPA likewise interpreted IRC section 48A(g) –

based on the plain language and the context provided by sections 

402(i) and 421(a) – to mean that use of technology, or emission 

performance, from a facility for which the credit is allowed 

cannot, by itself, support a finding that the technology or 

performance level is adequately demonstrated, but the 

information can corroborate an otherwise supported determination 

or otherwise provide part of the basis for such a 

determination.171 The EPA also proposed to interpret the phrase 

“with respect to which a credit is allowed under this section” 

as referring to the entire phrase “use of technology (or level 

of emission reduction...) and [] achievement of any emission 

reduction..., by or at one or more facilities.” Thus, if 

technology A received a tax credit, but technology B at the same 

facility did not, the constraint would not apply to technology 

B.

172

Some commenters supported the EPA’s proposed 

interpretation. Others contended that the EPA’s interpretation 

would allow it to support a BSER determination even where

 

170 Id.

171 Id. p. 13.

172 Id. p. 14.
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EPAct05 facility information comprised 99 percent of the 

supporting information for a BSER determination because that

determination would not be based “solely” on EPAct05 sources. 

These commenters urged the EPA to conclude that a determination 

“solely” on the basis of information from EPAct05-assisted 

facilities is any determination where “but for” that 

information, the EPA could not justify its chosen standard as 

the BSER.

174 Other commenters argued that the provisions bar the 

EPA from all consideration of EPAct05 facilities when 

determining that a technology or level of performance is 

adequately demonstrated.

In this final rule, the EPA is adopting the interpretations 

of all three provisions that it proposed, largely for the 

reasons previously advanced. The EPA thus interprets these 

provisions to preclude the EPA from relying solely on the 

experience of facilities that received DOE assistance, but not 

to preclude the EPA from relying on the experience of such 

facilities in conjunction with other information. This reading 

of sections 402(i) and 421(a) is consistent with the views of 

the only court to date to consider the matter.176

 

174 Comments of AFPM/API p. 46.

176 State of Nebraska v. EPA, 2014 U.S. Dist. LEXIS 141898 at n. 

1 (D. Nebr. 2014). (“But the Court notes that § 402(i) only 

forbids the EPA from considering a given technology or level of 

emission reduction to be adequately demonstrated solely on the 
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The EPA notes that the extreme hypothetical posed in the 

comments (where the EPA might avoid a limitation on its 

consideration of EPAct05-assisted facilities by including a mere 

scintilla of evidence from non-EPAct05 facilities) is not 

presented here, where the principal evidence that partial postcombustion CCS is a demonstrated and feasible technology comes 

from sources which received no assistance of any type under 

EPAct05. The EPA also concludes that the “but for” test urged by 

these commenters is an inappropriate reading of the term 

“solely” in sections 402(i) and 421(a), as any piece of evidence 

may be a necessary, or “but for,” cause without being a 

sufficient, or “sole,” cause.177 Nonetheless, if the “but for” 

test were applicable here, the available evidence would satisfy 

it. 

Other commenters took the extreme position that the EPAct05 

provisions bar all consideration of a facility’s existence if 

 

basis of federally-funded facilities. 42 U.S.C. § 15962(i). In 

other words, such technology might be adequately demonstrated if 

that determination is based at least in part on non-federallyfunded facilities”)(emphasis original).

177 For example, any vote of a Justice on the Supreme Court may 

be a necessary but not sufficient cause. In a 5-4 decision, the 

decision of the Court would have been different “but for” the 

assent of Justice A or Justice B, who were in the majority. But 

it would be incorrect to say that the assent of Justice A was 

the “sole” reason for the outcome, when the decision also 

required the assent of Justice B. 
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the facility received EPAct05 assistance.178 The EPA does not 

accept this argument because it is contrary to both the plain 

statutory language179 (see Chapter 2 of the Response-to-Comment 

document) and to Congress’s intent that the EPAct05 programs 

advance the commercialization of clean coal technology. For the 

same reason, the EPA does not accept some commenters’ suggestion

that sections 402(i), 421(a), and 48A(g) preclude the EPA from 

considering NETL’s cost projections for CCS, which base cost 

estimates on up-to-date vendor quotes reflecting costs for the 

CCS technology being utilized at the Boundary Dam Unit #3 

facility (a facility receiving no assistance under EPAct05), but 

also considers that to-be-built plants will no longer be firstof-a kind. See generally Section V.I.2 below. Commenters suggest 

that the EPAct05 requires that the EPA treat future plants as 

“first of a kind” when projecting costs, as if EPAct05 

facilities simply did not exist. This reading is contrary to the 

text of the provisions, which as noted, relates specifically to 

a source’s performance and operation (whether a technology is 

 

178 Supplemental Comments of Murray Energy (comment 9498) p. 11.

179 With respect to sections 402(i) and 421(a), commenters fail 

to reconcile their reading of the statute with the Act’s 

grammatical structure, as explained in detail in chapter 2 of 

the Response-to-Comment document. One commenter supported its 

reading by adding suggested text to the statutory language, a 

highly disfavored form of statutory construction. Comments of 

UARG, p.124 n.38. With respect to section 48A(g), commenters 

misread the phrase “considered to indicate,” and do not explain 

how their reading of all three provisions together is tenable.
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demonstrated, and the level of performance achieved by use of 

technology), not to sources’ existence. NETL’s cost projections, 

on the other hand, merely acknowledge the evident fact that CCS 

technologies exist, and reasonably project that they will 

continue to develop. See Section V.I.2. The NETL cost estimates, 

moreover, are based on vendor quotes for the CCS technology in 

use at the Boundary Dam facility, a Canadian plant which 

obviously is not a recipient of EPAct05 assistance. See sections 

V.D.2.a and V. I.2 below.

In any case, as shown in Section V below, the EPA finds 

that a new highly-efficient SCPC EGU implementing partial postcombustion CCS is the best system of emission reduction 

adequately demonstrated and is doing so based in greater part on 

performance of facilities receiving no assistance under EPAct05, 

and on other information likewise not having any connection to 

EPAct05 assistance. The corroborative information from EPAct05 

facilities, though supportive, is not necessary to the EPA’s 

findings.

I. Severability 

This rule has numerous components, and the EPA intends that 

they be severable from each other to the extent that they 

function separately. For example, the EPA intends that each set 

of BSER determinations and standards of performance in this 

rulemaking be severable from each other set. That is, the BSER 
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determination and standard of performance for newly constructed 

fossil fuel-fired electric utility steam generating units are 

severable from all the other BSER determinations and standards 

of performance, and the same is true for the BSER determination 

and standard of performance for modified fossil fuel-fired 

electric utility steam generating units, and so on. It is 

reasonable to consider each set of BSER determination and 

standard of performance to be severable from each other set of 

BSER determination and standard of performance because each set 

is independently justifiable and does not depend on any other 

set. Thus, in the event that a court should strike down any set 

of BSER determination and standard of performance, the remaining 

BSER determinations and standards of performance should not be 

affected.

J. Certain Projects under Development

In the January 2014 proposal, the EPA indicated that the 

proposed Wolverine EGU project (Rogers City, Michigan) appeared 

to be the only fossil fuel-fired steam generating unit that was 

currently under development that may be capable of “commencing 

construction” for NSPS purposes at the time of the proposal. See 

79 FR 1461. The EPA also acknowledged that the Wolverine EGU, as 

designed, would not meet the proposed standard of 1,100 lb 

CO2/MWh for new utility steam generating EGUs. The EPA proposed

that, at the time of finalization of the proposed standards, if 
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the Wolverine project remains under development and has not 

either commenced construction or been canceled, we anticipated

proposing a standard of performance specifically for that 

facility. Additional discussion of the approach can be found in 

the proposal or in the technical support document in the docket 

entitled “Fossil Fuel-Fired Boiler and IGCC EGU Projects under 

Development: Status and Approach.”

In December 2013 – after the proposed action was signed, 

but before it was published – Wolverine Power Cooperative 

announced that it was cancelling construction of the proposed 

coal-fired power plant in Rogers City, MI.180 Therefore, we are 

not finalizing the proposed exclusion for that project.

In the January 2014 proposal, the EPA also identified two 

other fossil fuel-fired steam generating EGU projects that, as 

currently designed, would not meet the proposed 1,100 lb CO2/MWh 

emissions standard — the Plant Washington project in Georgia and 

the Holcomb 2 project in Kansas. We indicated that, at the time 

of the proposal, those projects appeared to remain under 

development but that the project developers had represented that 

the projects have commenced construction for NSPS purposes and, 

thus, would not be new sources subject to the proposed or final 

 

180 “Wolverine ends plant speculation in Rogers City”, The Alpena 

News, December 17, 2013. 

http://www.thealpenanews.com/page/content.detail/id/527862/Wolve

rine-ends-plant-speculation-in-Rogers-City.html?nav=5004.
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NSPS. Based solely on the developers’ representations, the EPA 

indicated that those projects, if ultimately fully constructed, 

would be existing sources, and would thus not be subject to the 

standards of performance in this final action. 

To date, neither developer has sought a formal EPA 

determination of NSPS applicability. As we specified in the 

January 2014 proposal – and we reiterate here - if such an 

applicability determination concludes that either the Plant 

Washington (GA) project or the Holcomb 2 (KS) project did not 

commence construction prior to January 8, 2014 (the publication 

of the January 2014 proposal), then the project should be 

situated similarly to the disposition the EPA proposed for the 

Wolverine project. Accordingly, the EPA is finalizing in this 

action that if it is determined that either of these projects 

has not commenced construction as January 8, 2014, then that 

project will be addressed in the same manner as was proposed for 

the Wolverine project.

In public comments submitted in response to the January 

2014, Power4Georgians (P4G), the Plant Washington developer, 

reiterated that they had executed binding contracts for the 

purchase and erection of the facility boiler prior to 

publication of the January 2014 proposal and believe that the 

binding contracts are sufficient to constitute commencement of 

construction for purposes of the NSPS program, so that they are 
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existing rather than new sources for purposes of this rule.

181

Public comments submitted by Tri-State Generation and 

Transmission Association and Sunflower Electric Power 

Corporation, the developers of the Holcomb 2 project, discussed 

the cost incurred in the development of the project. They also 

indicated they had awarded contracts for the turbine/generator 

purchase and had negotiated a rail-supply agreement that 

provides for the delivery of fuel to the proposed Holcomb 2 

site. The developers did not, however, explicitly characterize 

the construction status of the project.182 Other groups submitted 

comments contending that neither project has actually commenced 

construction.

In October 2013, the Kansas Supreme Court invalidated the 

2010 air pollution permit granted to Sunflower Electric Power 

Corporation by the Kansas Department of Health and Environment 

(KDHE).183 In May 2014, the KDHE issued an air quality permit 

addendum for the proposed Holcomb 2 coal plant. The addendum 

addressed federal regulations that the Kansas Supreme Court held 

had been overlooked in the initial permitting determination. In 

June 2014, the Sierra Club filed an appeal with the Kansas 

 

181 Docket entry: EPA-HQ-OAR-2013-0495-9403.

182 Docket entry: EPA-HQ-OAR-2013-0495-9599.

183 “Kansas High Court Invalidates 895-MW Coal Project Air 

Permit”, Power Magazine, 10/10/2013, available at: 

www.powermag.com/kansas-high-court-invalidates-2010-895-mw-coalproject-air-permit/.
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Appellate Court challenging the legality of the May 2014 permit. 

Since the publication of the January 2014 proposal, the EPA is 

unaware of any physical construction activity at the proposed 

Holcomb 2 site. 

In October 2014, the Plant Washington project was given an 

18-month air permit extension by the Georgia Environmental 

Protection Division (EPD). However, as with the Holcomb 

expansion project, the EPA is unaware of any physical 

construction that has taken place at the proposed Plant 

Washington site and a recent audit of the project described it 

as “dormant”.184

Based on this information, it appears that these sources 

have not commenced construction for purposes of section 111(b) 

and therefore would likely be new sources should they actually 

be constructed. As noted above, the EPA proposed that, if these 

projects are determined to not have commenced construction for 

NSPS purposes prior to the publication of the proposed rule, 

they will be addressed in the same manner proposed for the 

Wolverine project. 79 FR 1461. We are finalizing that proposal 

here. However, because these units may never actually be fully 

built and operated, we are not promulgating a standard of 

 

184 http://www.macon.com/2015/06/23/3811798/audit-sandersvillecoal-plant.html.
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performance at this time because such action may prove to be 

unnecessary.185 

There is one possible additional new EGU, the Two Elk 

project in Wyoming. In a supporting TSD accompanying the January 

2014 proposal, we discussed the Two Elk project and relied on 

developer statements and state acquiescence that the unit had 

commenced construction for NSPS purposes before January 8, 

2014.186 We did not, therefore, propose any special section 

111(b) standard for the project. Some commenters maintained that 

a continuous program of construction at the facility has not 

been maintained and that if the plant is ultimately constructed,

it should be classified as a new source under CAA section 

111(b). These comments were not specific enough to change the

EPA’s view of the project for purposes of this rulemaking. We 

 

185 In the proposed emission guidelines for existing EGUs, the 

EPA did not include estimates of emissions for either Plant 

Washington or the Holcomb 2 unit in baseline data used to 

calculate proposed state goals for Georgia and Kansas. It 

appears that the possibility of these plants actually being 

built and operating is too remote. If either unit eventually 

seeks an applicability determination and that unit is determined 

to be an existing source, and there is reliable evidence that 

the source will operate, then the source will be subject to the 

final 111(d) rule and the EPA will allow the state to adjust its 

state goal to reflect adjustment of the state’s baseline data so 

as to include the unit. Guidance for adjustment of state goals 

is provided in the record for the EPA’s final CAA section 111(d) 

rulemaking.

186 “Fossil Fuel-Fired Boiler and IGCC EGU Projects Under 

Development: Status and Approach”, Technical Support Document at 

pp. 10-1 Docket Entry: EPA-HQ-OAR-2013-0495-0024.
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accordingly continue to rely on developer statements that this 

facility has commenced construction and would not be a new 

source for purposes of this proceeding. 

IV. Summary of Final Standards for Newly Constructed, Modified, 

and Reconstructed Fossil Fuel-fired Electric Utility Steam 

Generating Units

This section sets forth the standards for newly 

constructed, modified, and reconstructed steam generating units 

(i.e., utility boilers and IGCCs). We explain the rationale for 

the final standards in Sections V (newly constructed steam 

generating unit), VI (modified steam generating units), and VII 

(reconstructed steam generating units).

A. Applicability Requirements and Rationale 

We generally refer to fossil fuel-fired electric utility 

generating units that would be subject to an emission standard 

in this rulemaking as “affected” or “covered” sources, units, 

facilities or simply as EGUs. These units meet both the 

definition of “affected” and “covered” EGUs subject to an 

emission standard as provided by this rule, and the criteria for 

being considered “new,” “modified” or “reconstructed” sources as 

defined under the provisions of CAA section 111 and the EPA’s 

regulations. This section discusses applicability for newly 

constructed, modified, and reconstructed steam generating units.
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1. General Applicability Criteria

The EPA is finalizing applicability criteria for new, 

modified, and reconstructed electric utility steam generating 

units (i.e., utility boilers and IGCC units) in 40 CFR part 60,

subpart TTTT that are similar to the applicability criteria for 

those units in 40 CFR part 60, subpart Da (utility boiler and 

IGCC performance standards for criteria pollutants), but with 

some differences. The proposed applicability criteria, relevant 

comments, and final applicability criteria specific to newly 

constructed, modified, and reconstructed steam generating units 

are discussed below.

The applicability requirements in the proposal for newly 

constructed EGUs included that a utility boiler or IGCC unit

must: (1) be capable of combusting more than 250 MMBtu/h heat 

input of fossil fuel; (2) be constructed for the purpose of 

supplying, and actually supply, more than one-third of its 

potential net-electric output capacity to any utility power 

distribution system (that is, to the grid) for sale on an annual 

basis; (3) be constructed for the purpose of supplying, and 

actually supply, more than 219,000 MWh net-electric output to 

the grid on an annual basis; and (4) combust over 10 percent 

fossil fuel on a heat input basis over a 3-year average. At 

proposal, applicability was determined based on a combination of 

design and actual operating conditions that could change 
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annually depending on the proportion and the amount of 

electricity actually sold and on the proportion of fossil fuels

combusted by the unit.

In the proposal for modified and reconstructed EGUs, we 

proposed a broader applicability approach such that

applicability would be based solely on design criteria and would 

be identical to the applicability requirements in subpart Da. 

First, we proposed electric sales criteria that the source be

constructed for the purpose of selling more than one-third of 

their potential electric output and more than 219,000 MWh to the 

grid on an annual basis, regardless of the actual amount of 

electricity sold (i.e., we did not include the applicability 

criterion that the unit actually sell the specified amount of 

electricity on an annual basis). In addition, we proposed a base 

load rating criterion that the source be capable of combusting 

more than 250 MMBtu/h of fossil fuel, regardless of the actual 

amount of fossil fuel burned (i.e., we did not include the 

fossil fuel-use criterion that an EGU actually combust more than 

10 percent fossil fuel on a heat input basis on a 3-year 

average). Under this approach, applicability would be known 

prior to the unit actually commencing operation and would not 

change on an annual basis. We also proposed that the final 

applicability criteria would be consistent for newly 

constructed, reconstructed, and modified units. The proposed
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broad applicability criteria would still not have included

boilers and IGCC units that were constructed for the purpose of 

selling one-third or less of their potential output or 219,000 

MWh or less to the grid on an annual basis. These units are not 

covered under subpart Da (the utility boiler and IGCC EGU 

criteria pollutant NSPS) but are instead covered as industrial 

boilers under subpart Db (industrial, institutional, and 

commercial boilers NSPS) or subpart KKKK (the combustion turbine 

criteria pollutant NSPS). 

We solicited comment on whether, to avoid implementation 

issues related with different interpretations of “constructed 

for the purpose,” the total and percentage electric sales 

criteria should be recast to be based on permit conditions. The 

“constructed for the purpose” language was included in the 

original subpart Da rulemaking. At that time, the vast majority 

of new steam generating units were clearly base load units. The 

“constructed for the purpose” language was intended to exempt 

industrial CHP units. These units tend to be relatively small 

and were not the focus of the rulemaking. In addition, units not 

meeting the electric sales applicability criteria in subpart Da 

would be covered by other NSPS so there is limited regulatory 

incentive, or impact to the environment, for owners/operators to 

avoid applicability with the utility NSPS. However, for new 

units, there is no corresponding industrial unit CO2 NSPS and 
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existing units could debate their original intent (i.e., the 

purpose for which they were constructed) in an attempt to avoid 

applicability under section 111(d) requirements. Consequently, 

there could be a regulatory incentive for owners/operators to 

circumvent the CO2 NSPS applicability. For units that avoid 

coverage, there would also be a corresponding environmental 

impact. For example, an owner/operator of a new unit could 

initially request a permit restriction to limit electric sales 

to less than one-third of potential annual electric output, but 

amend the operating permit shortly after operation has commenced 

to circumvent the intended applicability. Many existing units 

were initially built with excess capacity to account for 

projected load growth and were intended to sell more than onethird of their potential electric output. However, due to 

various factors (lower than expected load growth, availability 

of other lower cost units, etc.), certain units might have sold 

less than one-third of their potential electric output, at least 

during their initial period of operation. Therefore, the EPA has 

concluded that determining applicability based on whether a unit 

is “constructed for the purpose of supplying one-third or more 

of its potential electric output and more than 219,000 MWh as 

net-electric sales” (emphasis added) could create applicability 

uncertainty for both the regulated community and regulators. In 

addition, we have concluded that applicability based on actual 
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operating conditions (i.e., actual electric sales) is not ideal 

because applicability would not be known prior to determining 

compliance and could change annually.

This action finalizes applicability criteria based on 

design characteristics and federally enforceable permit 

restrictions included in each individual permit. Based on 

restrictions, if any, on annual total electric sales in the 

operating permit, it will be clear from the time of construction 

whether or not a new unit is subject to this rule. The

applicability includes all utility boilers and IGCC units unless 

the electric sales restriction was in the original and remains 

in the current operating permit without any lapses (this is to 

be consistent with the ‘constructed for the purpose of’ criteria 

in subpart Da). We have concluded that this approach is 

equivalent to, but clearer than, the existing language used in 

subpart Da. In addition, we have concluded that it is important 

for both the 111(b) and 111(d) requirements for electric-only 

steam generating units that the permit restriction limiting 

annual electric sales be included in both the original and 

current operating permit. Without this restriction, existing 

units could avoid obligations under state plans developed as 

part of the 111(d) program by amending their operating permit to 

limit total annual electric sales to one-third of potential 

electric output. These units would not be subject to any GHG 
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NSPS requirements because they would not meet the 111(b) or 

111(d) applicability criteria and, at this time, there is no 

NSPS that would cover these units. As described in Section III, 

industrial CHP and dedicated non-fossil units also are not 

affected EGUs under this final action. 

In this rule, we are finalizing the definition of a steam 

generating EGU as a utility boiler or IGCC unit that: (1) has a 

base load rating greater than 260 GJ/h (250 MMBtu/h) of fossil 

fuel (either alone or in combination with any other fuel) and 

(2) serves a generator capable of supplying more than 25 MW-net 

to a utility distribution system (i.e., for sale to the grid). 

However, we are not establishing final CO2 standards for certain 

EGUs. These include: (1) steam generating units and IGCC units

that are currently subject to - and have been continuously 

subject to - a federally enforceable permit limiting annual 

electric sales to one-third or less of their potential electric 

output (e.g., limiting hours of operation to less than 2,920 

hours annually) or limiting annual electric sales to 219,000 MWh 

or less; (2) units subject to a federally enforceable permit 

that limits the use of fossil fuels to 10 percent or less of the 

unit’s heat input capacity on an annual basis; and (3) CHP units

that are subject to a federally enforceable permit condition 

limiting annual total electric sales to no more than their
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design efficiency times their potential electric output, or to 

no more than 219,000 MWh, whichever is greater.

2. Applicability Specific to Newly Constructed Steam Generating 

Units

In CAA section 111(a)(2), a “new source” is defined as any 

stationary source, the construction or modification of which is 

commenced after the publication of regulations (or if earlier, 

proposed regulations) prescribing a standard of performance 

under this section which will be applicable to such source. 

Accordingly, for purposes of this rule, a newly constructed 

steam generating EGU is a unit that fits the definition and 

applicability criteria of a fossil fuel-fired steam generating 

EGU and commences construction on or after January 8, 2014, 

which is the date that the proposed standards were published for 

those sources (see 79 FR 1430). 

3. Applicability Specific to Modified Steam Generating Units

In CAA section 111(a)(4), a “modification” is defined as 

“any physical change in, or change in the method of operation 

of, a stationary source which increases the amount of any air 

pollutant emitted by such source or which results in the 

emission of any air pollutant not previously emitted.” The EPA, 
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through regulations, has determined that certain types of 

changes are exempt from consideration as a modification.187

For purposes of this rule, a modified steam generating EGU 

is a unit that fits the definition and applicability criteria of 

a fossil fuel-fired steam generating EGU and that modifies on or 

after June 18, 2014, which is the date that the proposed 

standards were published for those sources (see 79 FR 34960). 

4. Applicability Specific to Reconstructed Steam Generating 

Units

The NSPS general provisions (40 CFR part 60, subpart A)

provide that an existing source is considered a new source if it 

undertakes a “reconstruction,” which is the replacement of 

components of an existing facility to an extent that: (1) the 

fixed capital cost of the new components exceeds 50 percent of 

the fixed capital cost that would be required to construct a 

comparable entirely new facility, and (2) it is technologically 

and economically feasible to meet the applicable standards.188

For purposes of this rule, a reconstructed steam generating 

EGU is a unit that fits the definition and applicability 

criteria of a fossil fuel-fired steam generating EGU and that 

reconstructs on or after June 18, 2014, which is the date that 

 

187 40 CFR 60.2, 60.14(e).

188 40 CFR 60.15.
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the proposed standards were published for those sources (see 79 

FR 34960). 

B. Best System of Emission Reduction

1. BSER for Newly Constructed Steam Generating Units

In the January 2014 proposal, the EPA proposed that highly 

efficient new generation technology implementing partial CCS is 

the BSER for GHG emissions from new steam generating EGUs. (See 

generally 79 FR 1468-1469.) In this final action, the EPA has 

determined that the BSER for newly constructed steam generating 

units is a new highly efficient supercritical pulverized coal 

(SCPC) boiler implementing partial CCS technology to the extent 

of removal efficiency that meets a final emission limitation of 

1,400 lb CO2/MWh-g. The final standard of performance is less 

stringent than the proposed emission limitation of 1,100 lb 

CO2/MWh-g. This change, as will be discussed in greater detail 

later in this preamble, is in response to public comments and 

reflects both a re-examination of the potential BSER 

technologies and the most recent, reliable information regarding 

technology costs. A newly constructed fossil fuel-fired 

supercritical utility boiler will be able to meet the final 

standard by implementing post-combustion carbon capture treating 

a slip-stream of the combustion flue gas. Alternative potential 

compliance paths are to build a new IGCC unit and co-fire with 

natural gas (or use pre-combustion carbon capture on a slip-
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stream), or for a supercritical utility boiler to co-fire with 

natural gas.

The EPA of course realizes that the final standard of 

performance (1,400 lb CO2/MWh-g) differs from the proposed 

standard (1,100 lb CO2/MWh-g). The EPA notes further, however,

that the methodology for determining the final standard of 

performance is identical to that at proposal – determining that 

a new highly efficient generating technology implementing some 

degree of partial CCS is the BSER, with that degree of 

implementation being determined based on the reasonableness of 

costs. A key means of assessing the reasonableness of cost at 

proposal was comparison of the levelized cost of electricity 

(LCOE) with that of other dispatchable, base load non-NGCC 

generating options. We have maintained that approach in 

identifying BSER for the final standard. Applying this 

methodology to the most recent cost information has led the EPA 

to adopt the final standard of performance of 1,400 lb CO2/MWh-g. 

See Section V.H at Table 8 below. This final standard reflects 

the level of emission reduction achievable by a highly efficient 

SCPC implementing the degree of partial CCS that remains cost 

comparable to the other non-NGCC dispatchable base load 

generating options. 

The BSER for newly constructed steam generating EGUs in the 

final rule is very similar to that in the proposal. In this 
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final action, the EPA finds that a highly efficient new SCPC EGU 

implementing partial CCS to the degree necessary to achieve an 

emission of 1,400 lb CO2/MWh-g is the BSER. Contrary to the 

January 2014 proposal, the EPA finds that IGCC technology –

either alone or implementing partial CCS – is not part of the 

BSER, but rather is a viable alternative compliance option. As 

noted at proposal, a BSER typically advances performance of a 

technology beyond current levels of performance. 79 FR 1465, 

1471. Similarly, promotion of technology innovation can be a 

relevant factor in BSER determinations. Id. and Section

III.H.3.d above. For these reasons, the EPA at proposal voiced 

concerns about adopting standards that would allow an IGCC to 

comply without utilizing CCS for slip-stream control. Id. at 

1471. The final standard of 1,400 lb CO2/MWh-g, adopted as a 

means of assuring reasonableness of costs, allows IGCC units to 

comply without using partial CCS. Thus, although the standard 

can be met by a highly efficient new IGCC unit using 

approximately 3 percent partial CCS (see Sections V.E and V.H.7 

below), the EPA does not believe that implementation of partial 

CCS at such a low level, while technically feasible, is the 

option that utilities and project developers will choose. The 

EPA believes that IGCC project developers will either choose to 

meet the final standard by co-firing with natural gas - which 

would be a less costly and very straightforward process for a 
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new IGCC unit - or they will choose to install CCS equipment 

that will allow the facility to achieve much deeper CO2

reductions than required by this rule – likely to co-produce 

chemicals and/or to capture large volumes of CO2 for use in EOR 

operations. Similarly, project developers may also – as an 

alternative to utilizing partial CCS technology – meet the final 

standard by co-firing approximately 40 percent natural gas in a

new highly efficient SCPC EGU.

While the EPA does not find that IGCC technology – either 

alone or with implementation of partial CCS - is part of the 

BSER for new steam generating EGUs, we remain convinced that it 

is technically feasible (see Section V.E below) and believe that 

it represents a viable alternative compliance option that some 

project developers will consider to meet the final standard 

issued in this action. The EPA notes further that IGCC is 

available at reasonable cost (see Table 9 below), and involves 

use of an advanced technology. So, although the final standard 

reflects performance of a BSER which includes partial CCS, even 

in the instances that a compliance alternative might be 

utilized, that alternative would both result in emission 

reductions consistent with use of the BSER, and would reflect 

many of the underlying principles and attributes of the BSER 

(costs are both reasonable, not greatly dissimilar than BSER, no 

collateral adverse impacts on health or the environment, and 
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reflects performance of an advanced technology).

In reaching the final standard of performance, the EPA is 

aware that at proposal, the agency stated that it was not 

“currently considering” a standard of performance as high as 

1,400 lb CO2/MWh-g. 79 FR 1471. However, in that same discussion,

the EPA noted the reasons for its reservations (chiefly 

reservations about the extent of emission reductions, promotion 

of advanced CO2 control technologies, and whether the standard 

could be met by either utility boilers or IGCC units co-firing 

with natural gas, or otherwise complying without utilizing 

partial CCS), and we specifically solicited comment on the 

issue: “We request that commenters who suggest emission rates 

above 1,200 lb CO2/MWh address potential concerns about providing 

adequate reductions and technology development to be considered 

BSER.” Id. The proposal thus both solicited comment on higher 

emission standards (including 1,400 lb CO2/MWh-g based on a less 

aggressive rate of partial CCS), and provided ample notice of 

the methodology the EPA would use to determine the final BSER

and the corresponding final standard.

189 For these reasons, the 

 

189 Although co-firing with natural gas is not part of BSER, as 

noted above, it could be part of a compliance pathway for either 

SCPC or IGCC units. In this regard, a number of commenters 

addressed the issue of natural gas co-firing, indicating that 

there were circumstances where it could be part of BSER. See 

e.g. Comments of Exelon Corp. p. 12; Comments of the Sierra Club

p. 108. See Northeast Md. Waste Disposal Authority v. EPA, 358 
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EPA believes that it provided adequate notice of this potential 

outcome at proposal, that the final standard of performance was 

reasonably foreseeable, and that the final standard is a logical 

outgrowth of the proposed rule. Allina Health Services v. 

Sebelius, 746 F. 3d 1102, 1107 (D.C. Cir. 2014).

A more detailed discussion of the rationale for the final 

BSER determination and of other systems that were also 

considered is provided in Section V.P of this preamble.

190

2. BSER for Modified Steam Generating Units

The EPA has determined that, as proposed, the BSER for 

steam generating units that trigger the modification provisions 

 

F.3d 936, 952 (D.C. Cir. 2004); Appalachian Power v. EPA, 135 

F.3d 791, 816 (D.C. Cir. 1998) (commenters understood a matter 

was under consideration when they addressed it in comments).

190 Certain commenters maintained that the BSER determination 

does not comply with (purportedly) binding legal requirements 

created by regulations implementing the Information Quality Act. 

These comments are mistaken as a matter of both law and fact. 

The Information Quality Act does not create legal rights in 

third parties (see, e.g. Mississippi Comm’n on Environmental 

Quality v. EPA, no. 12-1309 at 84 (D.C. Cir. June 2, 2015)), and 

the OMB Guidelines are not binding rules but rather, as their 

title indicates, guidance to assist agencies. See State of 

Mississippi, 744 F.3d at 1347 (the Guidelines provide “policy 

and procedural guidance”, are meant to be “flexible” and are to 

be implemented differently by different agencies accounting for 

circumstances). There are also significant factual omissions and 

mischaracterizations in these comments regarding peer review of 

the proposed standard and underlying record information. The 

complete response to these comments is in chapter 2 of the RTC. 

See also Section V.I.2.a and N below describing findings of the 

SAB panel that materials of the National Energy Technology 

Laboratory had been fully and adequately peer reviewed, and that 

the EPA findings related to sequestration of captured CO2

reflected the best available science.
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is the modified unit’s own best potential performance. However, 

as explained below, the final BSER determination and the scope 

of modifications to which the final standards apply differ in 

some important respects from what the EPA proposed.

The EPA proposed that the modified unit’s best potential 

performance would be determined depending upon when the unit 

implemented the modification (i.e., before or after being 

subject to an approved CAA section 111(d) state plan). For units 

that commenced modification prior to becoming subject to an 

approved CAA section 111(d) state plan, the EPA proposed unitspecific standards consistent with each modified unit’s best 

one-year historical performance (during the years from 2002 to 

the time of the modification) plus an additional two percent 

reduction. For sources that commenced modification after 

becoming subject to an approved CAA section 111(d) plan, the EPA 

proposed that the unit’s best potential performance would be 

determined from the results of an efficiency audit. 

The final standards in this action do not depend upon when 

the modification commences, as long as it commences after June 

18, 2014. We are establishing emission standards for large 

modifications in this rule and deferring at this time the 

setting of standards for small modifications. 

In this final action, the EPA is issuing final emission 

standards for affected steam generating units that implement 
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larger modifications that are consistent with the proposed BSER 

determination for those units. The final standard for those

sources that implement larger modifications is a unit-specific 

emission limitation consistent with each modified unit’s best 

one-year historical performance (during the years from 2002 to 

the time of the modification), but does not include the 

additional two percent reduction that was proposed in the 

January 2014 proposal.

In this action, the EPA is not finalizing standards for 

those sources that conduct smaller modifications and is 

withdrawing the proposed standards for those sources. See 

Section XV below.

A more detailed discussion of the rationale for the BSER 

determination and final standards is provided in Section VI of 

this preamble.

3. BSER for Reconstructed Steam Generating Units

Consistent with our proposal, the EPA has determined that 

the BSER for reconstructed steam generating units is the most 

efficient demonstrated generating technology for these types of 

units (i.e., meeting a standard of performance consistent with a 

reconstructed boiler using the most efficient steam conditions 

available, even if the boiler was not originally designed to do 

so). A more detailed discussion of the rationale for the BSER 

determination and the final standards is provided in Section VII
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of this preamble.

C. Final Standards of Performance

The EPA is issuing final standards of performance for newly 

constructed, modified, and reconstructed affected steam 

generating units based on the degree of emission reduction 

achievable by application of the best system of emission 

reduction for those categories, as described above. The final 

standards are presented below in Table 6.

Table 6. Final Standards of Performance for New, Modified, and 

Reconstructed Steam Generating Units

Source Description Final Standard*

lb CO2/MWh-g

New Sources

All newly 

constructed steam 

generating EGUs

1,400

Modified Sources

Sources that 

implement larger

modifications –

those resulting in 

an increase in 

hourly CO2

emissions (lb 

CO2/hr) of more 

than 10 percent

Best annual 

performance (lb 

CO2/MWh-g) during 

the time period 

from 2002 to the 

time of the 

modification

Reconstructed Sources Large** 1,800

Reconstructed Sources Small** 2,000

* Standards are to be met over a 12-operating-month compliance 

period.

**Large units are those with heat input capacity of > 2,000 

mmBtu/hr; small units are those with heat input capacity of ≤

2,000 mmBtu/hr.
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For newly constructed and reconstructed steam generating 

units and for modified steam generating sources that result in 

larger hourly increases of CO2 emissions, the EPA is finalizing 

standards in the form of a gross energy output-based CO2 emission 

limit expressed in units of mass per useful energy output, 

specifically, in pounds of CO2 per megawatt-hour (lb CO2/MWhg).191 The standard of performance will apply to affected EGUs

upon the effective date of the final action. 

Compliance with the final standard will be demonstrated by

summing the emissions (in pounds of CO2) for all operating hours 

in the 12-operating-month compliance period and then dividing

that value by the sum of the useful energy output (on a gross

basis, i.e., gross megawatt-hours) over the rolling 12-

operating-month compliance period. The final rule requires 

rounding of emission rates with numerical values greater than or 

equal to 1,000 to three significant figures and rounding of 

rates with numerical values less than 1,000 to two significant 

figures.

 

191 Note that the standards for sources that conduct larger 

modifications is a unit-specific numerical standard based on the 

unit’s best one-year historical performance during the period 

from 2002 to the time of the modification. The unit-specific 

standard will also be in the form of a gross energy output-based 

CO2 emission limit expressed in pounds of CO2 per megawatt-hour 

(lb CO2/MWh-g).
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For newly constructed steam generating units, we proposed 

two options for the compliance period. We proposed that a newly 

constructed source could choose to comply with a 12-operatingmonth standard or with a more stringent standard over an 84-

operating-month compliance period, and we solicited comment on 

including an interim 12-operating-month standard (based on use 

of supercritical boiler technology, see 79 FR at 1448). We are 

not finalizing the proposed 84-operating-month compliance period 

option because the final standard of performance for newly 

constructed sources is less stringent than the proposed standard 

and because, as discussed in Section V below, we are identifying 

alternative compliance pathways for new steam generating EGUs.

Specifically, we have concluded that there are unlikely to be 

significant issues with short-term variability during initial 

operation, in view of both the reduced numerical stringency of 

the standard, and the availability of compliance alternatives.

The EPA notes that co-firing of natural gas can also serve as an 

interim means to reduce emissions if a new source operator 

believes additional time is needed to phase-in the operation of 

a CCS system. Therefore, the applicable final standards of 

performance for all newly constructed, modified, and 

reconstructed steam generating units must be met over a rolling 

12-operating-month compliance period.
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In the Clean Power Plan, which is a separate rulemaking 

under CAA section 111(d) published at the same time as the 

present rulemaking under CAA section 111(b), the EPA is 

promulgating emission guidelines for states to develop state 

plans regulating CO2 emissions from existing fossil fuel-fired 

EGUs. Existing sources that are subject to state plans under CAA 

section 111(d) may undertake modifications or reconstructions 

and thereby become subject to the requirements under section 

111(b) in the present rulemaking. In the section 111(d) Clean 

Power Plan rulemaking, the EPA discusses how undertaking a 

modification or reconstruction affects an existing source’s 

section 111(d) requirements.

V. Rationale for Final Standards for Newly Constructed Fossil 

Fuel-fired Electric Utility Steam Generating Units

In the discussion below, the EPA describes the rationale 

and justification of the BSER determination and the resulting 

final standards of performance for newly constructed steam 

generating units. We also explain why this determination is 

consistent with the constraints imposed by the EPAct05.

A. Factors Considered in Determining the BSER

In evaluating the final determination of the BSER for newly 

constructed steam generating units, the EPA considered the 

factors for the BSER described above, looked widely at all 

relevant information and considered all the data, information, 
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and comments that were submitted during the public comment 

period. We re-examined and updated the information that was 

available to us and concluded, as described below, that the 

final standard of 1,400 lb CO2/MWh-g is consistent with the 

degree of emission reduction achievable through the 

implementation of the BSER. This final standard of performance 

for newly constructed fossil fuel-fired steam generating units 

provides a clear and achievable path forward for the 

construction of new coal-fired generating sources that addresses 

GHG emissions.

B. Highly Efficient SCPC EGU Implementing Partial CCS as the 

BSER for Newly Constructed Steam Generating Units

In the sections that follow, we explain the technical 

configurations that may be used to implement BSER to meet the 

final standard, describe the operational flexibilities that 

partial CCS offers, and then provide the rationale for the final 

standard of performance. After that, we discuss, in greater 

detail, consideration of the criteria for the determination of 

the BSER. We describe why a highly efficient new SCPC EGU

implementing partial CCS in the amount that results in an 

emission limitation of 1,400 lb CO2/MWh-g best meets those 

criteria, including, among others, that such a system is 

technically feasible, provides meaningful emission reductions, 

can be implemented at a reasonable cost, does not pose non-air 
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quality health and environmental concerns or impair energy 

reliability, and consequently is adequately demonstrated. We 

also explain why the emission standard of 1,400 lb CO2/MWh-g is 

achievable, including under all circumstances reasonably likely 

to occur when the system is properly designed and operated. We 

also discuss alternative compliance options that new source 

project developers can elect to use, instead of SCPC with 

partial CCS, to meet the final standard of performance.

C. Rationale for the Final Emission Standards

1. The Proposed Standards

In the January 2014 proposal, the EPA proposed an emission 

limitation of 1,100 lb CO2/MWh-g, which a new highly efficient 

utility boiler burning bituminous coal could have met by 

capturing roughly 40 percent of its CO2 emissions and a new 

highly efficient IGCC unit could have met by capturing and 

storing roughly 25 percent of its CO2 emissions. The captured CO2

would then be securely stored in sequestration repositories 

subject to either Class II or Class VI standards under the 

Underground Injection Control program. The EPA arrived at the

proposed standard by examining the available CCS implementation 

configurations and concluding that the proposed standard at the 

corresponding levels of partial CCS best balanced the BSER 

criteria and resulted in an achievable emission level. The EPA 

also proposed to find that highly efficient new generation 
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implementing “full CCS” (i.e., more than 90 percent capture and 

storage) was not the BSER because the costs of that

configuration – for both utility boilers and IGCC units - are 

projected to substantially exceed the projected costs of other 

non-NGCC dispatchable technologies that utilities and project 

developers are considering (e.g., new nuclear and biomass). See 

generally 79 FR at 1477-78. Conversely, the EPA rejected highly 

efficient SCPC as the BSER because it would not result in 

meaningful emission reductions from any newly constructed PC 

unit. Id. at 1470. The EPA also declined to base the BSER on 

IGCC operating alone due to the same concern – lack of emission 

reductions from a new IGCC unit otherwise planned. Id.

2. Basis for the Final Standards

For this final action, the EPA reexamined the BSER options 

available at proposal. Those options are: (1) highly efficient 

generation without CCS, (2) highly efficient generation 

implementing partial CCS, and (3) highly efficient generation 

implementing full CCS. Consistent with our determination in the 

January 2014 proposal, we remain convinced that highly efficient 

generation (i.e., a new supercritical utility boiler or a new 

IGCC unit) without CCS does not represent the BSER because it 

does not achieve emission reductions beyond the sector’s 

business as usual, when options that do achieve more emission 

reductions are available. 79 FR 1470; see also Section V.P 
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below. We also do not find that a highly efficient new steam 

generating unit implementing full CCS is the BSER because, at 

this time, the costs are predicted to be significantly more than 

the costs for implementation of partial CCS and significantly 

more than the costs for competing non-NGCC base load, 

dispatchable technologies - primarily new nuclear generation -

and are, therefore, potentially unreasonable. See Section V.P.

As with the proposal, the EPA has determined the final BSER 

and corresponding emission limitation by appropriately balancing 

the BSER criteria and determining that the emission limitation 

is achievable. The final standard of performance of 1,400 lb 

CO2/MWh-g is less stringent than at proposal and reflects changes 

that are responsive to comments received on, and the EPA’s 

further evaluation of, the costs to implement partial CCS. The 

EPA has determined that a newly constructed highly efficient 

supercritical utility boiler burning bituminous coal can meet 

this final emission limitation by capturing 16 percent of the CO2

produced from the facility (or 23 percent if burning 

subbituminous or dried lignite), which would be either stored in 

on-site or off-site geologic sequestration repositories subject 

to control under either the Class VI (for geologic 

sequestration) or Class II (for Enhanced Oil Recovery) standards

under the UIC program. This BSER is technically feasible, as 

shown by the fact that post-combustion CCS technology – both the 
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capture and storage components - is demonstrated in full-scale 

operation within the electricity generating industry. There are 

also numerous operating results from smaller-scale projects that 

are reasonably predictive of operation at full-scale. It is 

available at reasonable cost, does not have collateral adverse 

non-air quality health or environmental impacts, and does not 

have adverse energy implications.

The proposed BSER was a highly efficient newly constructed 

steam generating EGU implementing partial CCS to an emission 

standard of 1,100 lb CO2/MWh-g. The final BSER is a highly 

efficient SCPC EGU implementing partial CCS to achieve an 

emission standard of 1,400 lb CO2/MWh-g. In both cases, the EPA 

specified that the BSER includes a “highly efficient” new EGU 

implementing partial CCS. This assumes that a new project 

developer will construct the most efficient generating 

technology available – i.e., a supercritical or ultrasupercritical utility boiler – that will inherently generate 

lower volumes of uncontrolled CO2 per MWh. See Section V.J below. 

A well performing and highly efficient new SCPC EGU will need to 

implement lower levels of partial CCS in order to meet the final 

standard of 1,400 lb CO2/MWh-g than a less efficient new steam 

generating EGU. The construction of highly efficient steam 

generating EGUs – as opposed to less efficient units such as a 

subcritical utility boiler – will result in lower overall costs 
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from decreased fuel consumption and the need for lower levels of 

required partial CCS to meet the final standard.

3. Consideration of Projects Receiving Funding Under the EPAct05

As noted in Section III.H.3.g above, the EPA’s 

determination of the BSER here includes review of recently 

constructed facilities and those planned or under construction

to evaluate the control technologies being used and considered. 

Some of the projects discussed in the January 2014 proposal, and 

discussed here in this preamble, received or are receiving 

financial assistance under the EPAct05 (P.L. 109-58). This 

assistance may include financial assistance from the Department 

of Energy (DOE), as well as receipt of the federal tax credit 

for investment in clean coal technology under IRC Section 48A. 

As noted above, the EPA interprets these provisions as 

allowing consideration of EPAct05 facilities provided that such 

information is not the sole basis for the BSER determination, 

and particularly so in circumstances like those here, where the 

information is corroborative but the essential information 

justifying the determinations comes from facilities and other 

sources of information with no nexus with EPAct05 assistance. 

In the discussion below, the EPA explains its reliance on other 

information in making the BSER determination for new fossil 

fuel-fired steam generating units. The EPA notes that 

information from facilities that did not receive any DOE 
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assistance, and did not receive the federal tax credit, is 

sufficient by itself to support its BSER determination.

D. Post-Combustion Carbon Capture

In this section, we describe a variety of facts that 

support our conclusion that the technical feasibility of postcombustion carbon capture is adequately demonstrated. First, we 

describe the technology of post-combustion capture. We then 

describe EGUs that have previously utilized or are currently 

utilizing post-combustion carbon capture technology. This 

discussion is complemented by later sections that explain and 

justify our conclusions that the technical feasibility of other 

aspects of partial CCS are adequately demonstrated – namely, the 

transportation and carbon storage (see Sections V.M. and N). 

Further, the conclusions of this section are reinforced by the 

discussion in Section V.F. below, in which we identify 

commercial vendors that offer carbon capture technology and 

offer performance guarantees, and discuss industry and 

technology developers’ public pronouncements of their confidence 

in the feasibility and availability of CCS technologies. 

1. Post-combustion Carbon Capture – How it Works

Post-combustion capture processes remove CO2 from the 

exhaust gas of a combustion system – such as a utility boiler. 

It is referred to as “post-combustion capture” because the CO2 is 

the product of the combustion of the primary fuel and the 
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capture takes place after the combustion of that fuel. The 

exhaust gases from most combustion processes are at atmospheric 

pressure and are moved through the flue gas system by fans. The

concentration of CO2 in most combustion flue gas streams is 

somewhat dilute.192 Most post-combustion capture systems utilize 

liquid solvents193 that separate the CO2 from the flue gas in CO2

scrubber systems. Because the flue gas is at atmospheric 

pressure and is somewhat dilute, the solvents used for postcombustion capture are ones that separate the CO2 using chemical 

absorption (or chemisorption). Amine-based solvents194 are the 

most commonly used in post-combustion capture systems. In a 

chemisorption-based separation process, the flue gas is 

processed through the CO2 scrubber and the CO2 is absorbed by the 

liquid solvent and then released by heating to form a high 

purity CO2 stream. This heating step is referred to as “solvent 

regeneration” and is responsible for much of the “energy 

penalty” of the capture system. Steam from the boiler (or 

potentially from another external source) that would otherwise 

be used to generate electricity is instead used in the solvent 

 

192 The typical concentration of CO2 in the flue gas of a coalfired utility boiler is roughly around 15 volume percent.

193 A solvent is a substance (usually a liquid) that dissolves a 

solute (a chemically different liquid, solid or gas), resulting 

in a solution.

194 Amines are derivatives of ammonia (NH3) where one or more 

hydrogen atoms have been replaced by hydrocarbon groups.
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regeneration process. The development of advanced solvents –

those that are chemically stable, have high CO2 absorption 

capacities, and have low regeneration energy requirements – is

an active area of research. Many post-combustion solvents will 

also selectively remove other acidic gases such as SO2 and 

hydrochloric acid (HCl), which can result in degradation of the 

solvent. For that reason, the CO2 scrubber systems are normally 

installed downstream of other pollutant control devices (e.g., 

particulate matter and flue gas desulfurization controls) and in 

some cases, the acidic gases will need to be scrubbed to very 

low levels prior to the flue gas entering the CO2 capture system.

See also RIA chapter 5 (quantifying SO2 reductions resulting from 

this scrubbing process).

Additional information on post-combustion carbon capture –

including process diagrams - can be found in a summary technical 

support document.195

 

195 Technical Support Document – “Literature Survey of Carbon 

Capture Technology”, available in the rulemaking docket (Docket 

ID: EPA-HQ-OAR-2013-0495).
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2. Post-combustion Carbon Capture Projects that have not 

Received DOE Assistance through the EPAct05 or Tax Credits under

IRC Section 48A

a. Boundary Dam Unit #3

SaskPower’s Boundary Dam CCS Project in Estevan, a city in 

Saskatchewan, Canada, is the world’s first commercial-scale 

fully integrated post-combustion CCS project at a coal-fired 

power plant. The project fully integrates the rebuilt 110 MW 

coal-fired Unit #3 with a CO2 capture system using Shell Cansolv 

amine-based solvent to capture 90 percent of its CO2 emissions. 

The facility, which utilizes local Saskatchewan lignite, began 

operations in October 2014 and accounts of the system’s 

performance describe it as working even “better than 

expected.”196,197 The plant started by capturing roughly 75 percent 

of CO2 from the plant emissions and its operators plan to 

increase the capture percentage as they optimize the equipment 

 

196 “[W]e are achieving better than expected” operation out of 

the plant, SaskPower's Mike Marsh said April 8, 2015 in 

Washington, DC, summarizing the status of the first-of-a-kind 

plant in Saskatchewan, Canada, known as Boundary Dam Unit 3. 

Marsh spoke at a meeting of the National Coal Council, which 

advises the Energy Department on coal-related topics. From 

“Bolstering EPA’s NSPS, Canadian CCS Plant Working ‘Better Than 

Expected’”, Climate Daily News, Inside EPA/climate (April 08, 

2015); www.insideepa.com (subscription required).

197 “CCS performance data exceeding expectations at world-first 

Boundary Dam Power Station Unit #3”, 

http://www.saskpowerccs.com/newsandmedia/latest-news/ccsperformance-data-exceeding-expectations/.
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to reach full capacity. Initial indications are that the 

facility is producing more power than predicted and that the 

energy penalty (parasitic load – the energy needed to regenerate 

the CO2 capture solvent) is much lower than initially 

predicted.

198 Water use at the facility is consistent with levels 

that were predicted.199 The total project costs – for the power 

plant and the carbon capture plant – was $1.467B (CAD).200 The CO2

from the capture system is more than 99.999 percent pure with 

only trace levels of N2 in the product stream.201 This purity is 

food-grade quality CO2 and is a clear indication that the system 

is working well. The captured CO2 is transported by pipeline to 

nearby oil fields in southern Saskatchewan where it is being

used for EOR operations. Any captured CO2 that is not used for 

EOR operations will be stored in nearby deep brine-filled 

sandstone formations. Thus, the Boundary Dam Unit #3 project is 

demonstrating CO2 post-combustion capture, CO2 compression and 

transport, and CO2 injection for both EOR and geologic storage. 

 

198 Correspondence between Mike Monea (SaskPower) and Nick Hutson 

(EPA), February 20, 2015.

199 30 percent of the water used for cooling comes from the 

recycled or reclaimed water from the process itself; namely, 

water in the coal is reclaimed.

200 About $1.2B USD; roughly $700M (USD) for the carbon capture 

system, which was on budget.

201 “Boundary Dam – The Future is Here”, plenary presentation by 

Mike Monea at the 12th International Conference on Greenhouse Gas 

Technologies (GHGT-12), Austin, TX (October 2014). 
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The CCS system is fully integrated with the electricity 

production of the plant.

Some commenters noted that, at 110 MW, the Boundary Dam 

Unit #3 is a relatively small coal-fired utility boiler and 

thus, in the commenters’ view, does not demonstrate that such a 

system could be utilized at a much larger utility coal-fired 

boiler. However, there is nothing to indicate that the postcombustion system used at Boundary Dam could not be scaled-up 

for use at a larger utility boiler. In fact, the carbon capture 

system at Boundary Dam #3 is designed and constructed to 

implement “full CCS” – that is to capture more than 90 percent 

of the CO2 produced from the subcritical unit. A similarly-sized 

capture system – with no need for further scale-up - could be 

used to treat a slip-stream of a much larger supercritical 

utility boiler (a new unit of approximately 500 to 600 MW) in 

order to meet the final standard of performance of 1,400 lb 

CO2/MWh-g, which would only require partial CCS on the order of 

approximately 16 to 23 percent (depending on the coal used).

A “slip-stream” is a portion of the flue gas stream that 

can be treated separately from the bulk exhaust gas. It is not 

an uncommon configuration for the flue gas from a coal-fired 

boiler to be separated into two or more streams and treated 

separately in different control equipment before being 
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recombined to exit from a common stack.202 A slip-stream

configuration is often used to treat a smaller portion of the 

bulk flue gas stream as a way of testing or demonstrating a 

control device or measurement technology. For implementation of 

post-combustion partial carbon capture, a portion of the bulk 

flue gas stream would be treated separately to capture 

approximately 90 percent of the CO2 from that smaller slip-stream

of the flue gas. For example, in order to capture 20 percent of 

the CO2 produced by a coal-fired utility boiler, an operator 

would treat approximately 25 percent of the bulk flue gas stream 

(rather than treating the entire stream). Approximately 90 

percent of the CO2 would be captured from the slip-stream gas,

resulting in an overall capture of about 20 percent. 

In its study on the cost and performance of a range of 

carbon capture rates, the DOE/NETL determined that the slipstream approach was the most economical for carbon capture of 

less than 90 percent of the total CO2.

203 The advantage of the 

 

202 See Figure 1A from Atmospheric Environment, 43, 3974 (2009), 

for an example of this type of configuration.

203 “Cost and Performance of PC and IGCC for a Range of Carbon 

Capture”, Rev 1 (2013), DOE/NETL-2011/1498 p. 2 (“A literature 

search was conducted to verify that <90 percent CO2 capture is 

most economical using a ’slip-stream’ (or bypass) approach. 

Indeed, the slip-stream approach is more cost-effective for <90 

percent CO2 capture than removing reduced CO2 fractions from the 

entire flue gas stream, according to multiple peer-reviewed 

studies.” See also id. at 19, 21, 77, and 478 (documenting 
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slip-stream approach is that the capture system will be sized to 

treat a lower volume of flue gas flow, which reduces the size of 

the CO2 absorption columns, induced draft fans, and other 

equipment, leading to lower capital and operating costs.

The carbon capture system at Boundary Dam does not utilize 

the slip-stream configuration because it was designed to achieve 

more than 90 percent capture rates from the 110 MW facility. 

However, the same carbon capture equipment could be used to 

treat approximately 50 percent of the flue gas from a 220 MW 

facility – or 20 percent of the flue gas from a 550 MW facility. 

Thus, the equipment that is currently working very well (in 

fact, “better than expected”) at the Boundary Dam plant can be 

utilized for partial carbon capture at a much larger coal-fired 

unit without the need for further scale-up.

The experience at Boundary Dam is directly transferrable to 

other types of post-combustion sources, including those using 

different boiler types and those burning different coal types. 

There is nothing to suggest that the Shell CanSolv process would 

not work with other coal types and indeed, the latest NETL cost 

estimates assume that the capture technology would be used in a 

 

further that treating a slip-stream is the most economical 

approach).
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new unit using bituminous coal.204 The EPA is unaware of any 

reasons why the Boundary Dam technology would not be 

transferrable to another utility boiler at a different location 

at a different elevation or climate because the control 

technology is not climate or elevation-dependent.

Commenters also noted that the Boundary Dam Unit #3 project 

received financial assistance from both the Canadian federal 

government and from the Saskatchewan provincial government. But 

the availability of – or the lack of – external financial 

assistance does not affect the technical feasibility of the 

technology. Commenters further characterized Boundary Dam as a 

“demonstration project”. These descriptors are beside the point. 

Regardless of what the project is called or how it was financed,

the project clearly shows the technical feasibility of fullscale, fully integrated implementation of available postcombustion CCS technology, which in this case also appears to be 

commercially viable. 

 

204 In fact, in “Cost and Performance Baseline for Fossil Energy 

Plants Volume 1a: Bituminous Coal (PC) and Natural Gas to 

Electricity Revision 3”, DOE/NETL-2015/1723 (July 2015), Exh.2-3 

the Shell Cansolv process is used as the capture process for a 

new SCPC unit using bituminous coal rather than the subcritical 

PC unit at Boundary Dam that uses Canadian lignite. The study 

evidently assumes that the CanSolv process can be used 

effectively for bituminous coal since this type of coal is 

assumed for cost estimation purposes.
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The EPA notes that, although there is ample additional 

information corroborating that post-combustion CCS is 

technically feasible, which we describe below, the performance 

at Boundary Dam Unit #3 alone would be sufficient to support 

that conclusion. Essex Chemical Corp., 486 F. 2d at 436 (test 

results from single facility demonstrates achievability of 

standard of performance). As mentioned above, the postcombustion capture technology used at Boundary Dam is 

transferrable to all other types of utility boilers.

b. AES Warrior Run and Shady Point

AES’s coal-fired Warrior Run (Cumberland, MD) and Shady 

Point (Panama, OK) plants are both circulating fluidized bed 

(CFB) coal-fired power plants with carbon capture amine 

scrubbers developed by ABB/Lummus. The scrubbers were designed 

to process a slip-stream of each plant’s flue gas. At the 180 MW 

Warrior Run Plant, a plant that burns bituminous coal, 

approximately 10 percent of the plant’s CO2 emissions (about 

110,000 metric tons of CO2 per year) has been captured since 2000 

and sold to the food and beverage industry. At the 320 MW Shady 

Point Plant, a plant that burns a blend of bituminous and 

subbituminous coals, CO2 from an approximate 5 percent slipstream (about 66,000 metric tons of CO2 per year) has been 

captured since 2001. The captured CO2 from the Shady Point Plant 
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is also sold for use in the food processing industry.206 While 

these projects do not demonstrate the CO2 storage component of 

CCS, they clearly demonstrate the technical viability of partial 

CO2 capture. The capture of CO2 from a slip-stream of the bulk 

flue gas, as described earlier, is the most economical method 

for capturing less than 90 percent of the CO2. The amounts of 

partial capture that these sources have demonstrated – up to 10 

percent – is reasonably similar to the level, at 16 to 23 

percent, that the EPA predicts would be needed by a new highly 

efficient steam utility boiler to meet the final standard of 

performance. These facilities, which have been operating for 

multiple years, clearly show the technical feasibility of postcombustion carbon capture.

c. Searles Valley Minerals

Since 1978, the Searles Valley Minerals soda ash plant in 

Trona, CA has used post-combustion amine scrubbing to capture 

approximately 270,000 metric tons of CO2 per year from the flue 

gas of a coal-fired power plant that generates steam and power 

for on-site use. The captured CO2 is used for the carbonation of 

brine in the process of producing soda ash.207 Again, while the 

 

206 Dooley, J. J., et al. (2009). “An Assessment of the 

Commercial Availability of Carbon Dioxide Capture and Storage 

Technologies as of June 2009”. U.S. DOE, Pacific Northwest 

National Laboratory, under Contract DE-AC05-76RL01830.

207 IEA (2009), World Energy Outlook 2009, OECD/IEA, Paris.
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captured CO2 is not sequestered, this project clearly 

demonstrates the technical feasibility of the amine scrubbing 

system for CO2 capture from a coal-fired power plant.208 The fact 

that this system is an industrial coal-fired power plant rather 

than a utility coal-fired power plant is irrelevant as they both 

serve a similar purpose – the production of electricity.

Each of these processes indicate a willingness of industry 

to utilize available post-combustion technology for capture of 

CO2 for commercial purposes. Not one of the CO2 capture systems 

at Warrior Run, Shady Point, or Searles Valley was installed for 

regulatory purposes or as government-funded demonstration 

projects. They were installed to capture CO2 for commercial use. 

The fact that the captured CO2 was utilized rather than being 

stored is of no consequence in the consideration of the 

technical feasibility of post-combustion CO2 capture technology. 

These commercial operations have helped to improve the 

performance of scrubbing systems that are available today. For 

example, the heat duty (i.e., the energy needed to remove the 

CO2) has been reduced by about 5 times from the amine process 

originally used at the Searles Valley facility. The amine 

scrubbing process used at Boundary Dam is equally efficient, and 

 

208 Moreover, the final rule allows alternative means of storage 

of captured CO2 based on a case-by-case demonstration of

efficacy. See Section V.M.4 below.
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the amine scrubbing system to be used at the Petra Nova WA 

Parish project (Thompsons, TX) is projected to be as well.

209

3. Post-combustion Carbon Capture Projects that Received DOE 

Assistance through the EPAct05, but did not Receive Tax Credits 

under IRC Section 48A

The EPA considers the experiences from the CCS projects 

described above, coupled with evidence that the design of CCS is 

well accepted (also described above) and the strong support that 

CCS has received from vendors and others (described below) to 

adequately demonstrate that post-combustion partial CCS is 

technically feasible. The EPA finds that additional projects, 

described next, provide more support for that conclusion. These 

projects received funding under EPAct05 from the Department of 

Energy, but that does not disqualify them from being considered. 

See Section III.H.3 above.

a. Petra Nova WA Parish project

Petra Nova, a joint venture between NRG Energy Inc. and JX 

Nippon Oil & Gas Exploration, is constructing a commercial-scale 

post-combustion carbon capture project at Unit #8 of NRG's WA 

 

209 The heat duty for the amine scrubbing process used at Searles 

Valley in the mid-70’s was about 12 MJ/mt CO2 removed as compared 

to a heat duty of about 2.5 MJ/mt CO2 removed for the amine 

processes used at Boundary Dam and to be used at WA Parish.

“From Lubbock, TX to Thompsons, TX - Amine Scrubbing for 

Commercial CO2 Capture from Power Plants”, plenary address by 

Prof. Gary Rochelle at the 12th International Conference on 

Greenhouse Gas Technology (GHGT-12), Austin, TX (October 2014).
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Parish generating station southwest of Houston, Texas. The 

project is designed to utilize partial CCS by capturing 

approximately 90 percent of the CO2 from a 240 MW slip-stream of 

the 610 MW WA Parish facility. The project is expected to be 

operational in 2016 and thus does not yet directly demonstrate 

the technical feasibility or performance of the MHI amine 

scrubbing system. However, this project is a clear indication 

that the developers have confidence in the technical feasibility 

of the post-combustion carbon capture system.

The project was originally envisioned as a 60 MW slipstream demonstration and received DOE Clean Coal Power 

Initiative (CCPI) funding (as provided in EPAct05) on that 

basis. The developers later expanded the project to the larger 

240 MW slip-stream because of the need to capture greater

volumes of CO2 for EOR operations. No additional DOE or other 

federal funding was obtained for the expansion from a 60 MW 

slip-stream to a 240 MW slip-stream.

210

At 240 MW, the Petra Nova project will be the largest postcombustion carbon capture system installed on an existing coalfueled power plant. The project will use for EOR or will

 

210 Thus, even if the project received DOE assistance for the 

initial 60 MW design, the expansion of the project from 60 MW to 

240 MW should not be considered a DOE-assisted project. In any 

case, as described above, even without consideration of this 

facility at all, other information adequately demonstrates the 

technical feasibility of post-combustion CCS.
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sequester 1.6 million tons of captured CO2 each year. The project 

is expected to be operational in 2016. 

In 2014 project materials,

212 the project developer NRG 

recognized the importance of CCS technology by noting: 

The technology has the potential to enhance the longterm viability and sustainability of coal-fueled power 

plants across the U.S. and around the world. ... Postcombustion carbon capture is essential so that we can 

use coal to sustain our energy ecosystem while we 

begin reducing our carbon footprint.

According to NRG, the Petra Nova Carbon Capture Project 

will utilize “a proven carbon capture process,” jointly 

developed by Mitsubishi Heavy Industries, Ltd. (MHI) and the 

Kansai Electric Power Co., that uses a high-performance solvent 

for CO2 absorption and desorption.213 In using the MHI highperformance solvent, the Petra Nova project will benefit from 

pilot-scale testing of this solvent at Alabama Power’s Plant 

Barry and at other installations. WA Parish Unit #8 came on-line 

in 1982 and is thus an existing source that will not be subject 

to final standards of performance issued in this action. 

However, because it will be capturing roughly 35 percent of the 

 

212 WA Parish CO2 Capture Project Fact Sheet; available at 

www.nrg.com/documents/business/pla-2014-petranova-waparishfactsheet.pdf (2014).

213 The WA Parish project (described earlier) will utilize the 

KM-CDR Process®, which was jointly developed by MHI and the 

Kansai Electric Power Co., Inc. and uses the proprietary KS-1TM 

high-performance solvent for the CO2 absorption and desorption. 
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CO2 generated by the facility, its emissions will be below the 

final new source emission limitation of 1,400 lb CO2/MWh-g.

214

The captured CO2 from the WA Parish CO2 Capture Project will 

be used in EOR operations at mature oil fields in the Gulf Coast 

region. Using EOR at Hilcorp's West Ranch Oil Field, the 

production is expected to be boosted from around 500 barrels per 

day to approximately 15,000 barrels per day. Thus the project 

will utilize all aspects of CCS by capturing CO2 at the large 

coal-fired power plant, compressing the CO2, transporting it by 

pipeline to the EOR operations, and injecting it for EOR and 

eventual geologic storage. 

The carbon capture system at WA Parish will utilize a slipstream configuration. However, as noted, the system is designed 

to capture roughly 35 percent of the CO2 from WA Parish Unit #8

(90 percent of the CO2 from the 240 MW slip-stream from the 610 

MW unit). A carbon capture system of the same size as that used 

at WA Parish could be used to treat a 240 MW slip-stream from a 

1,000 MW unit in order to meet the final standard of performance 

of 1,400 lb CO2/MWh-g. 

Again, the experience at the WA Parish Unit #8 project will 

be directly transferable to post-combustion capture at a new 

 

214 Using emissions data reported to the Acid Rain Program, the 

EPA estimates that the CO2 emissions from the WA Parish Unit #8 

will be 1,250 – 1,300 lb CO2/MWh-g during operations with the 

post-combustion capture system.
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utility boiler, even though WA Parish Unit #8 is an existing 

source that has been in operation for over 30 years. In fact, 

retrofit of such technology at an existing unit can be more 

challenging than incorporating the technology into the design of 

a new facility. The experience will be directly transferrable to 

other types of post-combustion sources including those using 

different boiler types and those burning different coals. The 

amine scrubbing and associated systems are not boiler type- or 

coal-specific. The EPA is unaware of any reasons that the 

technology utilized at the WA Parish plant would not be 

transferrable to another utility boiler at a different location 

at a different elevation or climate, given that the technology 

is not dependent on either climate or topography. 

b. AEP/Alstom Mountaineer project

In September 2009, AEP began a pilot-scale CCS 

demonstration at its Mountaineer Plant in New Haven, WV. The 

Mountaineer Plant is a very large (1,300 MW) coal-fired unit 

that was retrofitted with Alstom’s patented chilled ammonia CO2

capture technology on a 20 MWe slip-stream of the plant’s 

exhaust flue gas. In May 2011, Alstom Power announced the 

successful operation of the chilled ammonia CCS validation 

project. The demonstration achieved capture rates from 75 

percent (design value) to as high as 90 percent, and produced CO2

at a purity of greater than 99 percent, with energy penalties 
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within a few percent of predictions. The facility reported 

robust steady-state operation during all modes of power plant 

operation, including load changes, and saw an availability of 

the CCS system of greater than 90 percent.215

AEP, with assistance from the DOE, had planned to expand 

the slip-stream demonstration to a commercial scale, fully 

integrated demonstration at the Mountaineer facility. The 

commercial-scale system was designed to capture at least 90 

percent of the CO2 from 235 MW of the plant's 1,300 MW total 

capacity. Plans were for the project to be completed in four 

phases, with the system to begin commercial operation in 2015. 

However, in July 2011, AEP announced that it would terminate its 

cooperative agreement with the DOE and place its plans to 

advance CO2 capture and storage technology to commercial scale on 

hold. AEP cited the uncertain status of U.S. climate policy as a 

contributor to its decision, but did not express doubts about 

the feasibility of the technology. See Section V.L below.

AEP also prepared a Front End Engineering & Design (FEED) 

Report,

216 explaining in detail how its pilot-scale work could be 

 

215 http://www.alstom.com/press-centre/2011/5/alstom-announcessucessful-results-of-mountaineer-carbon-capture-andsequestration-ccs-project/.

216 “CCS front end engineering & design report: American Electric 

Power Mountaineer CCS II Project. Phase 1”, pp 10-11; available 

at: http://www.globalccsinstitute.com/publications/aep-
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scaled up to successful full-scale operation, and to accommodate 

the operating needs of a full-scale EGU, including reliable 

generating capacity capable of cycling up and down to 

accommodate consumer demand. Recommended design changes to 

accomplish the desired scaling included detailed flue gas 

specifications, ranges for temperature, moisture and SO2 content; 

careful scrutiny of makeup water composition and temperature; 

quality and quantity of available steam to accommodate heat 

cycle based on unit load changes; and detailed scrutiny of 

material and energy balances.217 See Section V.G.3 below, 

addressing in more detail the record support for how CCS 

technology can be scaled up to commercial size in both pre- and 

post-combustion applications.

c. Southern Company/MHI Plant Barry

In June 2011, Southern Company and Mitsubishi Heavy 

Industries (MHI) launched operations at a 25 MW coal-fired 

carbon capture facility at Alabama Power’s Plant Barry. The 

facility, which completed the initial demonstration phase,

 

mountaineer-ii-project-front-end-engineering-and-design-feedreport

217 Id. at 11. The EPA does not view this information as being 

affected by the constraints in EPAct05. The information does not 

relate to use of technology, level of emission reduction by 

reason of use of technology, achievement of emission reduction 

by demonstration of technology, or demonstration of a level of 

performance. The FEED study rather explains engineering 

challenges which would remain at full scale and how those 

challenges can be addressed.
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captured approximately 165,000 metric tons of CO2 annually at a 

CO2 capture rate of over 90 percent. The facility employed the KM 

CDR Process, which uses a proprietary high performing solvent218

for CO2 absorption and desorption that was jointly developed by 

MHI and Japanese utility Kansai Electric Power Co. The captured 

CO2 has been transported via pipeline approximately 12 miles to

the Citronelle oil field where it is injected into the Paluxy

formation, a saline reservoir, for storage.219

Project participants have reported that “[t]he plant 

performance was stable at the full load condition with CO2

capture rate of 500 TPD at 90 percent CO2 removal and lower steam 

consumption than conventional capture processes.”220

E. Pre-Combustion Carbon Capture

As described earlier, the EPA does not find that IGCC 

technology – either alone or implementing partial CCS – is part 

of the BSER for newly constructed steam generating EGUs. 

However, as noted, there may be specific circumstances and 

business plans – such as co-production of chemicals or 

fertilizers, or capture of CO2 for use in EOR operations - that 

encourage greater CO2 emission reductions than are required by 

 

218 This is the same carbon capture system that is being utilized 

at the Petra Nova project at the NRG WA Parish plant.

219 Ivie, M.A. et al.; “Project Status and Research Plans of 500 

TPD CO2 Capture and Sequestration Demonstration at Alabama 

Power’s Plant Barry”, Energy Procedia 37, 6335 (2013).

220 Id.
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this standard. In this section, we describe and justify our 

conclusion that the technical feasibility of pre-combustion 

carbon capture is adequately demonstrated, indicating that this 

could be a viable alternative compliance pathway. First, we 

explain the technology of pre-combustion capture. We then 

describe EGUs that have previously utilized or are currently 

utilizing pre-combustion carbon capture technology. This 

discussion is complemented by other sections that conclude the 

technical feasibility of other aspects of partial CCS are 

adequately demonstrated – namely, post-combustion carbon capture 

(Section V.D) and sequestration (Sections V.M and V.N). Further, 

this section’s conclusions are reinforced by Section V.F, in 

which we identify commercial vendors that offer CCS performance 

guarantees as well as developers that have publicly stated their 

confidence in CCS technologies.

1. Pre-combustion Carbon Capture – How it Works

Pre-combustion capture systems are typically used with IGCC 

processes. In a gasification system, the fuel (usually coal or 

petroleum coke) is heated with water and oxygen in an oxygenlean environment. The coal (carbon), water and oxygen react to 

form primarily a mixture of hydrogen (H2) and carbon monoxide 

(CO) known as synthesis gas or syngas according to the following 

high temperature reaction:

3C + H2O + O2  H2 + 3CO
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In an IGCC system, the resulting syngas, after removal of 

the impurities, can be combusted using a conventional combustion 

turbine in a combined cycle configuration (i.e., a combustion 

turbine combined with a HRSG and steam turbine). The 

gasification process also typically produces some amount of CO2

221

as a by-product along with other gases (e.g., H2S) and inorganic 

materials originating from the coal (e.g., minerals, ash). The 

amount of CO2 in the syngas can be increased by “shifting” the 

composition via the catalytic water-gas shift (WGS) reaction. 

This process involves the catalytic reaction of steam (“water”) 

with CO (“gas”) to form H2 and CO2 according to the following 

catalytic reaction:

CO + H2O  CO2 + H2

An emission standard that requires partial capture of CO2

from the syngas could be met by adjusting the level of CO2 in the 

syngas stream by controlling the level of syngas “shift” prior 

to treatment in the pre-combustion acid gas treatment system. If 

a high level of CO2 capture is required, then multi-stage WGS 

reactors will be needed and an advanced hydrogen turbine will 

likely be needed to combust the resulting hydrogen-rich syngas.

 

221 The amount of CO2 in syngas depends upon the specific gasifier 

technology used, the operating conditions, and the fuel used; 

but is typically less than 20 volume percent 

(http://www.netl.doe.gov/technologies/coalpower/gasification/gas

ifipedia/4-gasifiers/4-3_syngastable2.html).
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Most syngas streams are at higher pressure and can contain 

higher concentrations of CO2 (especially if shifted to enrich the 

concentration). As such, the pre-combustion capture systems can 

utilize physical absorption (physisorption) solvents rather than 

the chemical absorptions solvents described earlier. Physical 

absorption has the benefit of relying on weak intermolecular 

interactions and, as a result, the absorbed CO2 can often be 

released (desorbed) by reducing the pressure rather than by 

adding heat. Pre-combustion capture systems have been used 

widely in industrial processes such as natural gas processing.

Additional information on pre-combustion carbon capture can 

be found in a summary technical support document.222

2. Pre-combustion Carbon Capture Projects that have not Received 

DOE Assistance through EPAct05 or Tax Credits under IRC Section 

48A

a. Dakota Gasification Great Plains Synfuels Plant

Each day, the Dakota Gasification Great Plains Synfuels 

Plant uses approximately 18,000 tons of North Dakota lignite in 

a coal gasification process that produces syngas (a mixture of 

CO, CO2, and H2), which is then converted to methane gas 

(synthetic natural gas) using a methanation process. Each day,

 

222 Technical Support Document – “Literature Survey of Carbon 

Capture Technology”, available in the rulemaking docket (Docket 

ID: EPA-HQ-OAR-2013-0495).
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the process produces an average of 145 million cubic feet of 

synthetic natural gas that is ultimately transported for use in

home heating and electricity generation.223

Capture of CO2 from the facility began in 2000. The Synfuels 

Plant, using a pre-combustion Rectisol® process, captures about 

3 million tons of CO2 per year - more CO2 from coal conversion 

than any facility in the world, and is a participant in the 

world's largest carbon sequestration project. On average about 

8,000 metric tons per day of captured CO2 from the facility is 

sent through a 205-mile pipeline to oil fields in Saskatchewan, 

Canada, where it is used for EOR operations that result in 

permanent CO2 geologic storage. The geologic sequestration of CO2

in the oil reservoir is monitored by the International Energy 

Agency (IEA) Weyburn CO2 Monitoring and Storage Project.

Several commenters to the January 2014 proposal argued that 

the Great Plains Synfuels facility is not an EGU, that it 

operates as a chemical plant, and that its experience is not 

translatable to an IGCC using pre-combustion carbon capture 

technology. The commenters noted that the Dakota facility can be 

operated nearly continuously without the need to adjust 

operations to meet cyclic electricity generation demands. In the 

January 2014 proposal, the EPA had noted that, while the 

 

223 http://www.dakotagas.com/Gasification/.
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facility is not an EGU, it has significant similarities to an 

IGCC and the implementation of the pre-combustion capture 

technology would be similar enough for comparison. See 79 FR at 

1435-36 and n. 11. We continue to hold this view.

As explained above, in an IGCC gasification system, coal 

(or petroleum coke) is gasified to produce a synthesis gas 

comprised of primarily CO, H2, and some amount of CO2 (depending 

on the gasifier and the specific operating conditions). A watergas-shift reaction using water (H2O, steam) is then used to shift 

the syngas to CO2 and H2. The more the syngas is “shifted,” the 

more enriched it becomes in H2. In an IGCC, power can be 

generated by directly combusting the un-shifted syngas in a 

conventional combustion turbine. If the syngas is shifted such 

that the resulting syngas is highly enriched in H2, then a 

special, advanced hydrogen turbine is needed. If CO2 is to be 

captured, then the syngas would need to be shifted either fully 

or partially, depending upon the level of capture required.224

The Dakota Gasification process bears essential

similarities to the just-described IGCC gasification system. As 

with the IGCC gasification system, the Dakota Gasification 

facility gasifies coal (lignite) to produce a syngas which is 

then shifted to increase the concentration of CO2 and to produce 

 

224 “Cost and Performance of PC and IGCC for a Range of Carbon 

Capture”, Rev 1 (2013), DOE/NETL-2011/1498.
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the desired ratio of CO and H2. As with the IGCC gasification 

system, the CO2 is then removed in a pre-combustion capture 

system, and the syngas that results is made further use of. For 

present purposes, only the manner in which the syngas is used

distinguishes the IGCC gasification system from the Dakota 

Gasification facility. In the IGCC process, the syngas is 

combusted. In the Dakota Gasification facility, the syngas is 

processed through a catalytic methanation process where the CO 

and H2 react to produce CH4 (methane, synthetic natural gas) and 

water. Importantly, the CO2 capture system that is used in the 

Dakota Gasification facility can readily be used in an IGCC EGU. 

There is no indication that the RECTISOL® process (or other 

similar physical gas removal systems) is not feasible for an 

IGCC EGU. In confirmation, according to product literature, 

RECTISOL®, which was independently developed by Linde and Lurgi, 

is frequently used to purify shifted, partially shifted or unshifted gas from the gasification of coal, lignite, and residual 

oil.225

b. International projects

There are some international projects that are in various 

stages of development that indicate confidence by developers in 

 

225 www.lindeengineering.com/en/process_plants/hydrogen_and_synthesis_gas_pla

nts/gas_processing/rectisol_wash/index.html.
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the technical feasibility of pre-combustion carbon capture. 

Summit Carbon Capture, LLC is developing the Caledonia Clean 

Energy Project, a proposed 570-megawatt IGCC plant with 90

percent CO2 capture that would be built in Scotland, U.K. 

Captured CO2 from the plant will be transported via on-shore and 

sub-sea pipeline for sequestration in a saline formation in the 

North Sea. The U.K. Department of Energy & Climate Change (DECC) 

recently announced funding to allow for feasibility studies for 

this plant.226 Commercial operation is expected in 2017.

227

The China Huaneng Group – with multiple collaborators, 

including Peabody Energy, the world’s largest private sector 

coal company - is building the 400 MW GreenGen IGCC facility in 

Tianjin City, China. The goal is to complete the power plant 

before 2020. Over 80 percent of the CO2 will be separated using 

pre-combustion capture technology. The captured CO2 will be used 

for EOR operations.228

Vattenfall and Nuon’s pilot project in Bugennum, The 

Netherlands involves carbon capture from coal- and biomass-fired 

IGCC plants. It has operated since 2011.229

 

226 http://www.downstreambusiness.com/item/Summit-Power-WinsFunding-Studies-Proposed-IGCC-CCS-Project_140878.

227 http://www.summitpower.com/projects/carbon-capture/.

228 http://sequestration.mit.edu/tools/projects/greengen.html.

229 Buggenum Fact Sheet: Carbon Dioxide Capture and Storage 

Project, Carbon Capture & Sequestration Technologies @ MIT, 

http://sequestration.mit.edu/tools/projects/buggenum.html.
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Approximately 100 tons of CO2 per day are captured from a 

coal- and petcoke-fired IGCC plant in Puertollano, Spain. The 

facility began operating in 2010.230

Emirates Steel Industries is expected to capture 

approximately 0.8Mt of CO2 per year from a steel-production 

facility in the United Arab Emirates. Full-scale operations are 

scheduled to begin by 2016.231

The Uthmaniyah CO2 EOR Demonstration Project in Saudi Arabia 

will capture 0.8 Mt of CO2 from a natural gas processing plant 

over three years. It is expected to begin operating in 2015.

232

The experience of the Dakota Gasification facility, coupled 

with the descriptions of the technology in the literature, the 

statements from vendors, and the experience of facilities 

internationally, are sufficient to support our determination 

that the technical feasibility of CCS for an IGCC facility is 

adequately demonstrated. The experience of additional 

facilities, described next, provides additional support.

 

230 Puertollano Fact Sheet: Carbon Dioxide Capture and Storage 

Project, Carbon Capture & Sequestration Technologies @ MIT, 

https://sequestration.mit.edu/tools/projects/puertollanto.html.

231 ESI CCS Project Fact Sheet: Carbon Dioxide and Storage 

Project, Carbon Capture & Sequestration Technologies @ MIT, 

http://sequestration.mit.edu/tools/projects/esi-ccs-project and 

https://www.globalccsinstitute.com/projects/large-scale-ccsprojects.

232 Utmaniyah CO2 EOR Demonstration Project, Global CCS Institute, 

http://www.globalccsinstitue.com/project/uthmaniyah-co2-eordemonstration-project-0.
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3. Pre-combustion Carbon Capture Projects that have Received DOE 

Assistance through EPAct05, but did not Receive Tax Credits 

under IRC Section 48A

a. Coffeyville Fertilizer

Coffeyville Resources Nitrogen Fertilizers, LLC, owns and 

operates a nitrogen fertilizer facility in Coffeyville, Kansas. 

The plant began operation in 2000 and is the only one in North 

America using a petroleum coke-based fertilizer production 

process. The petroleum coke is generated at an oil refinery 

adjacent to the plant. The petroleum coke is gasified to produce 

a hydrogen rich synthetic gas, from which ammonia and urea 

ammonium nitrate fertilizers are subsequently synthesized. 

As a by‐product of manufacturing fertilizers, the plant also 

produces significant amounts of CO2. In March 2011, Chaparral 

Energy announced a long-term agreement for the purchase of 

captured CO2 which is transported 68 miles via CO2 pipeline for 

use in EOR operations in Osage County, OK. Injection at the site 

started in 2013.

At least one commenter suggested that the cost and 

complexity of carbon capture from these and other industrial 

projects was significantly decreased because the sources already 

separate CO2 as part of their normal operations. The EPA finds 

this argument unconvincing. The Coffeyville process involves 
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gasification of a solid fossil fuel (pet coke), shifting the 

resulting syngas stream, and separation of the resulting CO2

using a pre-combustion carbon capture system. These are the 

same, or very similar, processes that are used in an IGCC EGU. 

The argument is even less convincing when considering that the 

Coffeyville Fertilizer process uses the SelexolTM pre-combustion 

capture process – the same process that Mississippi Power 

described as having been “in commercial use in the chemical 

industry for decades” and is expected by Mississippi Power to 

“pose little technology risk” when used at the Kemper IGCC EGU.

4. Pre-combustion Carbon Capture Projects that have Received DOE 

Assistance through EPAct05 and Tax Credits under IRC Section 48A

a. Kemper County Energy facility

Southern Company’s subsidiary Mississippi Power has 

constructed the Kemper County Energy Facility in Kemper County, 

MS. This is a 582 MW IGCC plant that will utilize local 

Mississippi lignite and includes a pre-combustion carbon capture 

system to reduce CO2 emissions by approximately 65 percent. The

pre-combustion solvent, SelexolTM has also been used extensively 

for acid gas removal (including for CO2 removal) in various 

processes. In filings with the Mississippi Public Service 

Commission for the Kemper project, Mississippi described the 

carbon capture system:
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The Kemper County IGCC Project will capture and 

compress approximately 65% of the Plant's CO2 [...] a 

process referred to as SelexolTM is applied to remove 

the CO2 such that it is suitable for compression and 

delivery to the sequestration and EOR process. [...} The 

carbon capture equipment and processes proposed in 

this project have been in commercial use in the 

chemical industry for decades and pose little 

technology risk. (emphasis added)233

Thus, Mississippi Power believes that, because the SelexolTM 

process has been in commercial use in the chemical industry for 

decades, it is well proven, and will pose little technical risk 

when used in the Kemper IGCC EGU.

b. Texas Clean Energy Project and Hydrogen Energy California 

project

The Texas Clean Energy Project (TCEP), a 400 MW IGCC 

facility located near Odessa, Texas will capture 90 percent of 

its CO2, which is approximately 3 million metric tons annually. 

The captured CO2 will be used for EOR in the West Texas Permian 

Basin. Additionally, the plant will produce urea and smaller 

quantities of commercial-grade sulfuric acid, argon, and inert 

slag, all of which will also be marketed. Summit has announced 

that they expect to commence construction on the project in 

 

233 Mississippi Power Company, Kemper County IGCC Certificate 

Filing, Updated Design, Description and Cost of Kemper IGCC 

Project, Mississippi Public Service Commission (MPSC) DOCKET NO. 

2009-UA-0014, filed December 7, 2009.
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2015.234 The facility will utilize the Linde Rectisol® gas 

cleanup process to capture carbon dioxide235 – the same process 

that has been deployed for decades, including at the Dakota 

Gasification facility, a clear indication of the developer’s 

confidence in that technology and further evidence that the 

Dakota Gasification carbon capture technology is transferable to 

EGUs.

F. Vendor Guarantees, Industry Statements, Academic Literature, 

and Commercial Availability

In this section, we describe additional information that 

supports our determination that CCS is adequately demonstrated 

to be technically feasible. This includes performance guarantees 

from vendors, public statements from industry officials, and 

review of the literature.

1. Performance Guarantees

The D.C. Circuit made clear in its first cases concerning 

CAA section 111 standards, and has affirmed since then, that 

performance guarantees from vendors are an important basis for 

supporting a determination that pollution technology is 

adequately demonstrated to be technically feasible. In 1973, in

Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir. 

 

234 “Odessa coal-to-gas power plant to break ground this year”, 

Houston Chronicle (April 1, 2015).

235 http://www.texascleanenergyproject.com/project/.
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1973), the Court upheld standards of performance for coal-fired 

steam generators based on “prototype testing data and full-scale 

control systems, considerations of available fuel supplies, 

literature sources, and documentation of manufacturer guarantees 

and expectations”(emphasis supplied)).

238 Subsequently, in Sierra 

Club v. Costle, the Court noted, in upholding the standard: “we 

find it informative that the vendors of FGD equipment 

corroborate the achievability of the standard.”239

Linde and BASF offer performance guarantees for carbon 

capture technology. The two companies are jointly marketing new, 

advanced technology for capturing CO2 from low pressure gas 

streams in power or chemical plants. In product literature,

240

they note that Linde will provide a turn-key carbon capture 

plant using a scrubbing process and solvents developed by BASF, 

 

238 See also Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 

401-02 (D.C. Cir. 1973) (“It would have been entirely 

appropriate if the Administrator had justified the standards ... 

on testimony from experts and vendors made part of the 

record.”).

239 Sierra Club v. Costle, 657 F.2d 298, 364 (D.C. Cir. 1981). 

See also National Petrochem & Refiners Assn v. EPA, 287 F. 3d 

1130, 1137 (D.C. Cir 2002) (noting that vendor guarantees are an 

indicia of availability and achievability of a technology-based 

standard since, notwithstanding a desire to promote sales, “a 

manufacturer would risk a considerable loss of reputation if its 

technology could not fulfill a mandate that it had persuaded EPA 

to adopt”).

197 www.intermediates.basf.com/chemicals/web/gastreatment/en/function/conversions:/publish/content/products-andindustries/gas-treatment/images/Linde_and_BASFFlue_Gas_Carbon_Capture_Plants.pdf.
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one of the world’s leading technical suppliers for gas 

treatment. They further note that:

The captured carbon dioxide can be used 

commercially for example for EOR (enhanced oil 

recovery) or as a building block for the production of 

urea. Alternatively it can be stored underground as a 

carbon abatement measure. [...] The PCC (Post-Combustion 

Capture) technology is now commercially available for 

lignite and hard coal fired power plant [...] 

applications.

The alliance between Linde, a world-leading gases 

and engineering company and BASF, the chemical 

company, offers great benefits [...] Complete capture 

plants including CO2 compression and drying ... Proven 

and tested processes including guarantee ... Synergies 

between process, engineering, construction and 

operation ... Optimized total and operational costs for 

the owner. (emphasis added)

In addition, other well-established companies that either

offer technologies that are actively marketed for CO2 capture 

from fossil fuel-fired power plants or that develop those power 

plants, have publicly expressed confidence in the technical 

feasibility of carbon capture. For example, Fluor has developed 

patented CO2 recovery technologies to help its clients reduce GHG 

emissions. The Fluor product literature241 specifically points to 

the Econamine FG PlusSM (EFG+) process, which uses an amine 

solvent to capture and produce food grade CO2 from postcombustion sources. The literature further notes that EFG+ is 

also used for carbon capture and sequestration projects, that 

 

241 www.fluor.com/client-markets/energy-chemicals/Pages/carboncapture.aspx.
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the proprietary technology provides a proven, cost-effective 

process for the removal of CO2 from power plant flue gas streams,

and that the process can be customized to meet a power plant's 

unique site requirements, flue gas conditions, and operating 

parameters.

Fluor has also published an article titled “Commercially 

Available CO2 Capture Technology” in which it describes the EFG+ 

technology.242 The article notes, “Technology for the removal of 

carbon dioxide (CO2) from flue gas streams has been around for 

quite some time. The technology was developed not to address the 

GHG effect but to provide an economic source of CO2 for use in 

enhanced oil recovery and industrial purposes, such as in the 

beverage industry.”

Mitshubishi Heavy Industries (MHI) offers a CO2 capture 

system that uses a proprietary energy-efficient CO2 absorbent 

called KS-1TM. Compared with the conventional monoethanolamine 

(MEA)-based absorbent, KS-1TM solvent requires less solvent 

circulation to capture the CO2 and less energy to recover the 

captured CO2. 

 

242 http://www.powermag.com/commercially-available-co2-capturetechnology/.
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In addition, Shell has developed the CANSOLV CO2 Capture 

System, which Shell describes in its product literature243 as a 

world leading amine based CO2 capture technology that is ideal 

for use in fossil fuel-fired power plants where enormous amounts 

of CO2 are generated. The company also notes that the technology 

can help refiners, utilities, and other industries lower their 

carbon intensity and meet stringent GHG abatement regulations by 

removing CO2 from their exhaust streams, with the added benefit 

of simultaneously lowering SO2 and NO2 emissions.

At least one commenter suggested that it is unlikely that 

any vendor is willing or able to provide guarantees of the 

performance of the system as a whole, arguing that this shows 

the system isn’t adequately demonstrated.

244 However, this 

suggestion is inconsistent with the performance guarantees 

offered for other air pollution control equipment. Particulate 

matter (PM) is controlled in the flue gas stream of a coal-fired 

power plant using fabric filters or electrostatic precipitators 

(ESP). The captured PM is then moved using PM/ash handling 

systems and is then transported for storage or re-use. It is 

unlikely that a fabric filter or ESP vendor would provide a 

performance guarantee for “the system as a whole.” Similarly, a 

 

243 http://www.shell.com/global/products-services/solutions-forbusinesses/globalsolutions/shell-cansolv/shell-cansolvsolutions/co2-capture.html.

244 Comments of Murray Energy, p. 73, EPA-HQ-OAR-2013-0495-10046.
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wet-FGD scrubber vendor would not be expected to provide a 

performance guarantee for handling, transportation, and re-use 

of scrubber solids for gypsum wallboard manufacturing. CO2

capture, transportation, and storage should, similarly, not be 

viewed as a single technology. Rather, these should be viewed as 

components of an overall system of emission reduction. Different 

companies will have expertise in each of these components, but 

it is unlikely that a single technology vendor would provide a 

guarantee for “the system as a whole.”

2. Academic and Other Literature 

 Climate change mitigation options – including CCS - are the 

subject of great academic interest, and there is a large body of 

academic literature on these options and their technical 

feasibility. In addition, other research organizations (e.g., 

U.S. national laboratories and others) have also published 

studies on these subjects that demonstrate the availability of 

these technologies. A compendium of relevant literature is 

provided in a Technical Support Document available in the 

rulemaking docket.245

 

245 Technical Support Document – “Literature Survey of Carbon 

Capture Technology”, available in the rulemaking docket (Docket 

ID: EPA-HQ-OAR-2013-0495).
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3. Additional Statements by Technology Developers

The discussion above of vendor guarantees, positive 

statements by industry officials, and the academic literature 

supports the EPA’s determination that partial CCS is adequately 

demonstrated to be technically feasible. Industry officials have 

made additional positive statements in conjunction with 

facilities that received DOE assistance under EPAct05 or the IRC

Section 48A tax credit. These statements provide further, 

although not necessary, support.

For example, Southern Company’s Mississippi Power has 

stated that, because the SelexolTM process has been used in 

industry for decades, the technical risk of its use at the 

Kemper IGCC facility is minimized. For example:

The carbon capture process being utilized for the 

Kemper County IGCC is a commercial technology referred 

to as SelexolTM. The SelexolTM process is a commercial 

technology that uses proprietary solvents, but is 

based on a technology and principles that have been in 

commercial use in the chemical industry for over 40 

years. Thus, the risk associated with the design and 

operation of the carbon capture equipment incorporated 

into the Plant’s design is manageable.246

And ... 

The carbon capture equipment and processes 

proposed in this project have been in commercial use 

 

246 Testimony of Thomas O. Anderson, Vice President, Generation 

Development for Mississippi Power, MS Public Service Commission 

Docket 2009-UA-14 at 22 (Dec. 7, 2009).
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in the chemical industry for decades and pose little 

technology risk.

247

Similarly, in an AEP Second Quarter 2011 Earnings 

Conference Call, Chairman and CEO Mike Morris said of the 

Mountaineer CCS project:

We are encouraged by what we saw, we’re clearly 

impressed with what we learned, and we feel that we 

have demonstrated to a certainty that the carbon 

capture and storage is in fact viable technology for 

the United States and quite honestly for the rest of 

the world going forward.

248

Some commenters have claimed that CCS technology is not 

technically feasible, and some further assert that vendors do 

not offer performance guarantees. For example, Alstom commented: 

The EPA referenced projects fail to meet the 

'technically feasible' criteria. These technologies 

are not operating at significant scale at any site as 

of the rule publication. We do not support mandating 

technology based on proposed projects (many of which 

may never be built).249

As discussed above, vendors do in fact offer performance 

guarantees. We further note that, as noted above, Boundary Dam

Unit #3 is a full-scale project that is successfully 

implementing full CCS with post-combustion capture, and Dakota 

 

247 Mississippi Power Company, Kemper County IGCC Certificate 

Filing, Updated Design, Description and Cost of Kemper IGCC 

Project, Mississippi Public Service Commission (MPSC) DOCKET NO. 

2009-UA-0014, filed December 7, 2009.

248 American Electric Power Co Inc AEP Q2 2011 Earnings Call 

Transcript, Morningstar, 

http://www.morningstar.com/earnings/28688913-american-electricpower-co-incaep-q2-2011-earnings-call-transcript.aspx.

249 Alstom Comments, p. 3.
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Gasification is likewise a full-scale commercial operation that 

is successfully implementing pre-combustion CCS technology. 

Moreover, as we explain above, this technology and performance 

is transferable to the steam electric generating sector. In 

addition, as noted above, technology providers and technology 

end users have expressed confidence in the availability and 

performance of CCS technology.

250

G. Response to Key Comments on the Adequacy of the Technical 

Feasibility Demonstration

1. Commercial Availability 

Some commenters asserted that CCS cannot be considered the 

BSER because it is not commercially available. There is no 

requirement, as part of the BSER determination, that the EPA 

finds that the technology in question is “commercially 

available.” As we described in the January 2014 proposal, the 

D.C. Circuit has explained that a standard of performance is 

“achievable” if a technology or other system of emission 

 

250 We note that before filing comments for this rule asserting 

that CCS is not technically feasible, Alstom issued public 

statements that, like the other industry officials quoted above, 

affirmed that CCS is technically feasible. According to an 

Alstom Power press release, Alstom President Phillipe Joubert, 

referencing results from an internal Alstom study, stated at an 

industry meeting: “We can now be confident that carbon capture 

technology (CCS) works and that it is cost-effective”. 

http://www.alstom.com/press-centre/2011/6/2011-06-16-CCS-costcompetiveness/.
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reduction can reasonably be projected to be available to new 

sources at the time they are constructed that will allow them to 

meet the standard, and that there is no requirement that the 

technology “must be in routine use somewhere.” See Portland 

Cement v. Ruckelshaus, 486 F. 2d at 391; 79 FR 1463. In any 

case, as discussed above, CCS technology is available through 

vendors who provide performance guarantees, which indicates that 

in fact, CCS is commercially available, which adds to the 

evidence that the technology is adequately demonstrated to be 

technically feasible. In sum, “[t]he capture and CO2 compression 

technologies have commercial operating experience with 

demonstrated ability for high reliability.”251

2. Must a technology or system of emission reduction be in fullscale use to be considered demonstrated?

Commenters maintained that the EPA can only show that a 

BSER is “adequately demonstrated” using operating data from the 

technology or system of emission reduction itself. This is 

mistaken. Since the very inception of the CAA section 111 

program, courts have noted that “[i]t would have been entirely 

appropriate if the Administrator had justified the standard, not 

on the basis of tests on existing sources or old test data in 

 

251 “Cost and Performance Baseline for Fossil Energy Plants 

Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity

Revision 3”, DOE/NETL-2015/1723 (July 2015) at p. 36.
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the literature, but on extrapolations from this data, on a 

reasoned basis responsive to comments, and on testimony from 

experts and vendors ....” Portland Cement v. Ruckelshaus, 486 F. 

2d at 401-02.

252

In a related argument, other commenters stated that a 

system cannot be adequately demonstrated unless all of its 

component parts are operating together.253 Courts have, in fact, 

accepted that the EPA can legitimately infer that a technology 

is demonstrated as a whole based on operation of component parts 

which have not, as yet, been fully integrated. Sur Contra la 

Contaminacion v. EPA, 202 F. 3d 443, 448 (1st Cir. 2000); Native 

Village of Point Hope v Salazar 680 F. 3d 1123, 1133 (9th Cir. 

2012). Moreover, all components of CCS are fully integrated at 

Boundary Dam: post-combustion full CCS is being utilized at a 

 

252 More recently, the D.C. Circuit stated: 

Our prior decisions relating to technology-forcing 

standards are no bar to this conclusion. We recognize 

here, as we have recognized in the past, that an 

agency may base a standard or mandate on future 

technology when there exists a rational connection 

between the regulatory target and the presumed 

innovation.

API v. EPA, 706 F. 3d at 480 (D.C. Cir 2013) (citing the section 

111 case Sierra Club v. Costle, 657 F. 2d at 364). The Senate 

Report to the original section 111 likewise makes clear that it 

was not intended that the technology “must be in actual routine 

use somewhere.” Rather, the question was whether the technology 

would be available for installation in new plants. S. Rep. 

No.91-1196, 91st Cong., 2d Sess. 16 (1970).

253 See, e.g., Comments of UARG p. 5.
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steam electric fossil fuel-fired plant, with captured carbon 

being transported via dedicated pipeline to both sequestration 

and EOR sites. All components are likewise demonstrated for precombustion full CCS at the Dakota Gas IGCC facility, except that 

the facility does not generate electricity, a distinction 

without a difference for this purpose (see Section V.E.2.a 

above).

The short of it is that the “EPA does have authority to 

hold the industry to a standard of improved design and 

operational advances, so long as there is substantial evidence 

that such improvements are feasible and will produce the 

improved performance necessary to meet the standard.” Sierra 

Club, 657 F. 2d at 364. The EPA’s task is to “identify the major 

steps necessary for development of the device, and give 

plausible reasons for its belief that the industry will be able 

to solve those problems in the time remaining”. API v. EPA, 706 

F. 3d at 480 (quoting NRDC v. EPA, 655 F. 2d 318, 333 (D.C. Cir. 

1981), and citing Sierra Club for this proposition).

3. Scalability of Pilot and Demonstration Projects

Commenters maintained that the EPA had no basis for 

maintaining that pilot and demonstration plant operations showed 

that CCS was adequately demonstrated. This is mistaken. In a 

1981 decision, Sierra Club v. Costle, the D.C. Circuit explained 

that data from pilot-scale, or less than full-scale operation, 
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can be shown to reasonably demonstrate performance at full-scale 

operation, although it is incumbent on the EPA to explain the 

necessary steps involved in scaling up a technology and how any 

obstacles may reasonably be surmounted when doing so.254 The EPA 

has done so here. 

Most obviously, the final standard reflects experience of 

full-scale operation of post-combustion carbon capture. Precombustion carbon capture is likewise demonstrated at fullscale. Second, the record explains in detail how CCS can be 

implemented at full-scale. The NETL cost and performance 

reports, indeed, contain hundreds of pages of detailed, 

documented explanation of how CCS can be implemented at fullscale for both utility boiler and IGCC facilities. See, for 

example, the detailed description of the following systems 

projected to be needed for a new supercritical PC boiler to 

capture CO2: coal and sorbent receiving and storage, steam 

generator and ancillaries, NOX control system, particulate 

 

254 Sierra Club v. Costle, 657 F. 2d 298, 341 n.157 and 380-84 

(D.C. Cir. 1981). See also Essex Chemical Corp. v. EPA, 486 F. 

2d at 440 (upholding achievability of standard of performance 

for coal-burning steam generating plants which hadn’t been 

achieved in full-scale performance based in part on “prototype 

testing data” which, along with vendor guarantees, indicated 

that the promulgated standard was achievable); Weyerhaeuser v. 

Costle, 590 F. 2d 1054 n. 170 (D.C. Cir. 1978) (use of pilot 

plant information to justify technology-based standard for Best 

Available Technology Economically Achievable under section 304 

of the Clean Water Act); FMC Corp. v. Train, 539 F. 2d 973, 983-

84 (4th Cir. 1976)(same).
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control, flue gas desulfurization, flue gas system, CO2 recovery 

facility, steam turbine generator system, balance of plant, and 

accessory electric plant, and instrumentation and control 

systems.255

It is important to note that, while some commenters 

challenged the EPA’s use of costs in the DOE/NETL cost and 

performance reports, commenters did not challenge the technical 

methodology in the work.

In addition, the AEP FEED study indicates how the 

development scale post-combustion CCS could be successfully 

scaled up to full-scale operation. See Section V.D.3.b above.

Tenaska Trailblazer Partners, LLC also prepared a FEED 

study257 for the carbon capture portion of the previously 

proposed Trailblazer Energy Center, a 760 MW SCPC EGU that was 

proposed to include 85 to 90 percent CO2 post-combustion capture. 

Tenaska selected the Fluor Econamine FG PlusSM technology and 

contracted Fluor to conduct the FEED study. One of the goals of 

the FEED study was to “[c]onfirm that scale up to a large 

commercial size is achievable.” Tenaska ultimately concluded 

that the study had achieved its objectives resulting in 

 

255 Cost and Performance Baseline for Fossil Energy Plants Volume 

1: Bituminous Coal and Natural Gas to Electricity; Revision 2a, 

pp. 57-74.

257 Final front-end engineering design (FEED) study report”, 

available at: www.globalccsinstitute.com/publications/tenaskatrailblazer-front-end-engineering-design-feed-study.
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“[c]onfirmation that the technology can be scaled up to 

constructable design at commercial size through (1) process and 

discipline engineering design and CFD (computational fluid 

dynamics) analysis, (2) 3D model development, and (3) receipt of 

firm price quotes for large equipment.”

Much has been written about the complexities of adding CCS 

systems to fossil fuel-fired power plants. Some of these 

statements come from high government officials. Some commenters 

argued that the EPA minimized – or even ignored – these 

publically voiced concerns in the discussion presented in the 

January 2014 proposal. On the contrary, the EPA has not 

minimized or ignored these complexities, but it is important to 

realize that most of these statements come in a different 

context: namely, implementing full CCS, or retrofitting CCS onto 

existing power plants. For example, in the Final Report of the 

President’s CCS Task Force, it was noted that “integration of 

CCS technologies with the power cycle at generating plants can 

present significant cost and operating issues that will need to 

be addressed to facilitate widespread, cost-effective deployment 

of CO2 capture.”258 This statement – and most of the statements in 

 

258 Report of the Interagency Task Force on Carbon Capture and 

Storage (August 2010), page 28. See also DOE Carbon Capture 

Website: “First generation CO2 capture technologies are currently 

being used in various industrial applications. However, in 

their current state of development, these technologies are not 
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this vein – are in reference to implementation of full CCS 

systems that capture more than 90 percent of the CO2 and many 

reference widespread implementation of such technology. The EPA 

has addressed the concerns regarding “significant cost” by 

finalizing a standard that relies on partial CCS which we show, 

in this preamble and in the supporting record, can be 

implemented at a reasonable, non-exorbitant cost. The Boundary 

Dam facility, in particular, demonstrates that the complexities 

of implementing CCS – even full CCS – can be overcome.

Concerns regarding “operating issues” are also often 

associated with implementation of full CCS – and often with 

implementation of full CCS as a retrofit to an existing source. 

Implementation of CCS at some existing sources may be 

challenging because of space limitations. That should not be an 

issue for a new facility because the developer will need to 

ensure that adequate space is available during the design of the 

facility. Constructing CCS technology at an existing facility 

 

ready for implementation on coal-based power plants because they 

have not been demonstrated at appropriate scale, requisite 

approximately one-third of the plant’s steam power to operate, 

and are cost prohibitive.” (Dec 2010); and Testimony of Dr. S. 

Julio Friedmann, Deputy Asst. Secretary of Energy for Clean

Coal, US Dept. of Energy, before the Subcommittee on Oversight 

and Investigations Committee on Energy and Commerce (Feb. 11, 

2014): CCS technologies at new coal-fired plants would result in 

"something like a 70 to 80 percent increase on the wholesale 

price of electricity."
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can be challenging even if there is adequate space because the 

positioning of the equipment may be awkward when it must be 

constructed to fit with the existing equipment at the plant. 

Some commenters noted the challenges of diverting steam from the 

plant’s steam cycle. Again, that is primarily an issue with full 

CCS implementation as a retrofit to an existing source. 

Consideration of steam requirements for solvent regeneration can 

be factored into the design of a new facility. We also note that 

issues of integration with the plant’s steam cycle are less 

challenging when implementing partial CCS.

Some commenters noted conclusions and statements from the 

CCS Task Force report as contradictory to the EPA’s 

determination of that partial CCS is technically feasible and 

adequately demonstrated. However, the EPA mentioned in the 

January 2014 proposal, and we emphasize again here, that the 

Task Force was charged with proposing a plan to overcome the 

barriers to the widespread, cost-effective deployment of CCS by 

2020. Implicit in all of the conclusions, recommendations, and 

statements of that final report is a goal of widespread 

implementation of full CCS – including retrofits of existing 

sources. This final action does not require – nor does it 

envision – the near term widespread implementation of full CCS. 

On the contrary, as we have noted several times in this 
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preamble, the EPA and others predict that very few, if any, new 

coal-fired steam generating EGUs will be built in the near term.

Thus, the EPA has provided an ample record supporting its 

finding that partial CCS is feasible at full-scale. As in Sierra 

Club, the EPA has presented evidence from full-scale operation, 

smaller scale installations, and reasonable, corroborated 

technical explanations of how the BSER can be successfully 

operated at full scale. See 657 F. 2d at 380, 382. Indeed, the 

EPA has more evidence here, as the baghouse standard in Sierra 

Club was justified based largely on less-than-full-scale 

operation. See 657 F.2d at 380 (there was only “limited data 

from one full scale commercial sized operation”), 376 (“the 

baghouses surveyed were installed at small plants”), and 341 

n.157; see also Section V.L, explaining why CCS is a more 

developed technology than FGD scrubbers were at the inception of 

the 1971 NSPS for this industry.

H. Consideration of Costs

CAA section 111(a) defines “standard of performance” as an 

emission standard that reflects the best system of emission 

reduction that is adequately demonstrated, “taking into account

[among other things] the cost of achieving such reduction.” 

Based on consideration of relevant cost metrics in the context 

of current market conditions, the EPA concludes that the costs 

associated with the final standard are reasonable.
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In reaching this determination, the EPA considered a host 

of different cost metrics, each of which illuminated a 

particular aspect of cost consideration, and each of which 

demonstrated that the costs of the final standard are 

reasonable. The EPA evaluated capital costs on a per-plant 

basis, responding to public comment that noted the particular

significance of capital costs for coal-fired EGUs. As in the 

proposal, the EPA also considered how the standard would affect 

the LCOE for individual affected EGUs as well as national, 

overall cost impacts of the standard. The EPA found that the 

anticipated cost impacts are similar to those in other 

promulgated NSPS – including for this industry - that have been 

upheld by the D.C. Circuit. The costs are also comparable to 

those of other base load technologies that might be selected on 

comparable energy portfolio diversity grounds. Finally, the EPA 

does not anticipate any significant overall nationwide costs or 

cost impacts on consumers because projected new generating 

capacity is expected to meet the standards even in the baseline.

Accordingly, after considering costs from a range of different 

perspectives, the EPA concludes that the costs of the final 

standard are reasonable.

1. Rationale at Proposal

At proposal, the EPA evaluated the costs of new coal-fired

EGUs implementing full (90 percent) and partial CCS. The EPA
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compared the predicted LCOE of those units against the LCOE of 

other new dispatchable technologies often considered for new 

base load power with fuel diversity, primarily including a new 

nuclear plant, as well as a new biomass-fired EGU. See 79 FR at 

1475-78. The levelized cost for a new steam EGU implementing

full CCS was higher than that of the other non-NGCC dispatchable 

technologies, and we did not propose to identify a new steam EGU 

implementing full CCS as BSER on that basis. Id. at 1477. The 

EPA proposed that a standard of performance of 1,100 lb CO2/MWhg, reflecting a new steam EGU implementing partial CCS, could be 

achieved at reasonable cost based on a comparison of the 

projected LCOE associated with achieving this standard with the 

alternative dispatchable technologies just mentioned. In the

January 2014 proposal, the EPA used LCOE projections for new 

fossil fuel-fired EGUs from a series of studies conducted by the 

DOE NETL. These studies – the “cost and performance studies” –

detail expected costs and performance for a range of technology 

options both with and without CCS.259 The EPA used LCOE 

 

259 For the cost estimates in the January 2014 proposal, the EPA 

used costs for new SCPC and IGCC units utilizing bituminous coal 

from the reports “Cost and Performance Baseline for Fossil 

Energy Plants Volume 1: Bituminous Coal and Natural Gas to 

Electricity”, Revision 2, Report DOE/NETL–2010/1397 (November 

2010) and “Cost and Performance of PC and IGCC Plants for a 

Range of Carbon Dioxide Capture”, DOE/NETL–2011/1498, May 27, 

2011. Additional cost and performance information can be found 

in additional volumes that are available at 
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projections for non-fossil dispatchable generation –

specifically nuclear and biomass – from the EIA AEO 2013. See 79 

FR 1435.

In addition, the EPA proposed that the costs to implement

partial CCS were reasonable because a segment of the industry 

was already accommodating them. Id. at 1478. The EPA also 

considered anticipated decreases in the cost of CCS 

technologies, the availability of government tax benefits, loan 

guarantees, and direct expenditures, and the opportunity to 

generate income from sale of captured CO2 for EOR. Id. at 1478-

80. The EPA noted that the proposed standard was not expected to 

lead to any significant overall costs or effects on electricity 

prices. Id. at 1480-81. The EPA also acknowledged the overall 

market context, noting that fossil steam EGUs, even without any 

type of CCS, are significantly more expensive than new natural

gas-fired electricity generation, but that some electricity 

suppliers might include new coal-fired generating sources in 

their generation portfolio, and would pay a premium to do so. 

Id. at 1478. 

2. Brief Summary of Cost Considerations under CAA Section 111

As explained above, CAA section 111(a) directs the EPA to 

“tak[e] into account the cost” of achieving reductions in 

 

http://www.netl.doe.gov/research/energy-analysis/energybaseline-studies.
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determining if a particular system of emission reduction is the 

best that is adequately demonstrated. The statute does not 

provide further guidance on how costs should be considered, thus 

affording the EPA considerable discretion in choosing a means of 

cost consideration. In addition, it should be noted that in 

evaluating the reasonableness of costs, the D.C. Circuit has 

upheld application of a variety of metrics, such as the amount 

of control costs or product price increases. See Section

III.H.3.(b).(1) above.

Following the directive of CAA section 111(a) and 

applicable precedent, the EPA evaluated relevant metrics and 

context in considering the reasonableness of the regulation’s

costs. The EPA’s findings demonstrate that the costs of the 

selected final standard are reasonable.

3. Current Context

The EIA projects that few new coal-fired EGUs will be 

constructed over the coming decade and that those that are built 

will apply CCS, reflecting the broad consensus of government, 

academic, and industry forecasters.

260 The primary reasons for 

 

260 Even in its sensitivity analysis that assumes higher natural 

gas prices and electricity demand, EIA does not project any 

additional coal beyond its reference case until 2023, in a case 

where power companies assume no GHGs emission limitations, and 

until 2024 in a case where power companies do assume GHGs 

emission limitations. EIA, “Annual Energy Outlook 2015,” 
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this projected trend include low electricity demand growth, 

highly competitive natural gas prices, and increases in the 

supply of renewable energy. In particular, U.S. electricity 

demand growth has followed a downward sloping trend for decades 

with future growth expected to remain very low.261 Furthermore, 

the EPA projects that, for any new fossil fuel-fired electricity 

generating capacity that is constructed through 2030, natural 

gas will be the overwhelming fuel of choice.

262 See RIA chapter 

4.

The EIA’s projection is confirmed by an examination of 

Integrated Resource Plans (IRPs) contained in a TSD in the 

docket for this rulemaking. IRPs are used by utilities to plan 

operations and investments in both owned generation and power 

purchase agreements over long time horizons. Though IRPs do not 

demonstrate a utility’s intent to pursue a particular generation 

technology, they do indicate the types of new generating 

technologies that a utility would consider for new generating 

capacity. The EPA’s survey of recent IRPs demonstrates that 

across the nation, utilities are not actively considering

 

DOE/EIA-0383(2015), April 2015, “[v]ery little unplanned coalfired capacity is added across all the AEO 2015 cases”, p. 26.

261 EIA, “Annual Energy Outlook 2015,” DOE/EIA-0383(2015), April 

2015, p. 8.

262 Integrated Planning Model (IPM) run by the EPA (v. 5.15) Base 

Case, available at www.epa.gov/powersectormodeling/.
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constructing new coal-fired generation without CCS in the near 

term.

Accordingly, construction of new uncontrolled coal-fired

generating capacity is not anticipated in the near term, even in 

the absence of the standards of performance we are finalizing in 

this rule, except perhaps in certain limited circumstances. 

In particular, commenters suggested that some developers 

might choose to build a new coal-fired EGU, despite its not 

being cost competitive, in order to achieve or maintain “fuel 

diversity.” Fuel diversity could provide important value by

serving as a hedge against the possibility that future natural 

gas prices will far exceed projected levels. 

Public announcements, including IRPs, confirm that 

utilities are interested in technologies that could provide or 

preserve fuel diversity within generating fleets. The Integrated 

Resource Plan TSD263 notes examples where the goal of fuel 

diversity was considered in IRPs; in many cases, these plans

considered new generation that would not rely on natural gas. In 

particular, several utilities that considered fuel diversity in 

developing their IRPs included new nuclear generation as a 

potential future generation strategy.

 

263 Technical Support Document - “Review of Electric Utility 

Integrated Resource Plans” (May 2015), available in the 

rulemaking docket EPA-HQ-OAR-2013-0495.
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In addition, the EPA recognizes that there may be interest 

in constructing a new combined-purpose coal-fired facility that 

would generate power as well as produce chemicals or CO2 for use 

in EOR projects. These facilities would similarly provide 

additional value due to the revenue streams from saleable 

chemical products or CO2.

264

As demonstrated below, the agency carefully considered the 

reasonableness of costs in identifying a standard that allows a 

path forward for such projects and rejects more stringent 

options that would impose potentially excessive costs. In fact, 

based on this careful consideration of costs, the EPA is 

finalizing a substantially lower cost standard than the one we 

proposed. At the same time, we note the unusual circumstances 

presented here, where the record, and indeed simple 

consideration of electricity market economics, demonstrates that 

non-economic factors such as fuel diversity are likely to drive 

any construction of new coal-fired generation. See also RIA 

chapter 4 (documenting that electric power companies will choose 

to build new EGUs that comply with the regulatory requirements 

of this rule even in its absence, primarily NGCC units, because 

of existing and expected market conditions). Under these 

 

264 The EPA may, of course, consider revenues generated as a 

result of application of pollution control measures in assessing 

the costs of a best system of emission reduction. See New York 

v. Reilly, 969 F.2d 1147, 1150-52 (D.C. Cir. 1992).
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circumstances, the EPA’s consideration of costs takes into 

account that higher costs can be viewed as reasonable when costs 

are not a paramount factor in new coal capacity decisions. At 

the same time, the EPA acknowledges and agrees with the public 

comments that such an argument, left unconstrained, could 

justify any standard and obviate all cost considerations.265 The 

EPA has reasonably cabined its consideration of costs by 

examining costs for comparable non-NGCC base load dispatchable 

technologies, as well as by considering capital costs and other 

cost metrics.266 This cost-reasonable standard will preserve the 

opportunity for such projects while driving new technology 

deployment.267

 

265 See, e.g., Comments of Murray Energy, pp. 79-80.

266 Indeed, the EPA is not only adopting a standard predicated on 

a lower rate of carbon capture than proposed, but also rejecting 

full CCS for reasons of cost. See Section V.P below. Thus, 

although the EPA has reasonably taken into account the current 

economic posture of the industry whereby new capacity is not 

cost-competitive and so would be added for non-economic reasons, 

it is not using that fact to negate consideration of cost here. 

See also Section V.I.4 below responding to comments that the 

incremental cost of partial CCS could prove the difference 

between constructing and not constructing new coal capacity.

267 In this rulemaking, our determination that the costs are 

reasonable means that the costs meet the cost standard in the 

case law no matter how that standard is articulated, that is, 

whether the cost standard is articulated through the terms that 

the case law uses, e.g., “exorbitant,” “excessive,” etc., or 

through the term we use for convenience, “reasonableness.”
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4. Consideration of Capital Costs

As noted above, CAA section 111 does not mandate any 

particular method for evaluating costs, leaving the EPA with 

significant discretion as to how to do so. One method is to 

consider the incremental capital costs required for a unit to 

achieve the standard of performance. 

The EPA included information on capital cost at proposal

and, as discussed further below, the LCOE metric relied upon at 

proposal and in this final rulemaking incorporates and fully 

reflects capital costs.

269 Nonetheless, extensive comment from 

industry representatives and others noted persuasively that 

fossil-steam units are very capital-intensive projects and 

recommended that a separate metric, solely of capital costs, be 

considered by the EPA in evaluating the final standard’s costs. 

Accordingly, the EPA has considered the final standard’s impact 

on the capital costs of new fossil-steam generation. The EPA has 

determined that the incremental capital costs of the final

standard are reasonable because they are comparable to those in 

prior regulations and to industry experience, and because the 

fossil steam electric power industry has been shown to be able 

 

269 See RIA chapter 4.5.4 and Fig. 4-3; see also “Cost and 

Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants”, 

DOE/NETL-2015/1720 (July 2015) p. 17.
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to successfully absorb capital costs of this magnitude in the 

past. 

Prior new source performance standards for new fossil steam 

generation units have had significant – yet manageable – impacts 

on the capital costs of construction. The EPA estimated that the 

costs for the 1971 NSPS for coal-fired EGUs were $19M for a 600 

MW plant, consisting of $3.6M for particulate matter controls,

$14.4M for sulfur dioxide controls, and $1M for nitrogen oxides 

controls, representing a 15.8 percent increase in capital costs 

above the $120M cost of the plant. See 1972 Supplemental 

Statement, 37 FR 5767, 5769 (March 21, 1972). The D.C. Circuit 

upheld the EPA’s determination that the costs associated with 

the final 1971 standard were reasonable, concluding that the EPA 

had properly taken costs into consideration. Essex Cement v. 

EPA, 486 F. 2d at 440. 

In reviewing the 1978 NSPS for coal-fired EGUs, the D.C. 

Circuit recognized that “EPA estimates that utilities will have 

to spend tens of billions of dollars by 1995 on pollution 

control under the new NSPS” and that “[c]onsumers will 

ultimately bear these costs.” Sierra Club, 657 F.2d at 314. The 

court nonetheless upheld the EPA’s determination that the 

standard was reasonable. Id. at 410.

The cost and investment impacts of the 1978 NSPS on 

electric utilities were subsequently evaluated in a 1982 
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Congressional Budget Office (CBO) retrospective study.

270 The CBO 

study highlighted that installation of scrubbers - capital 

intensive pollution control equipment that had “in effect” been 

mandated by the 1978 NSPS - increased capital costs for new EGUs 

by 10 to as much as 20 percent.271 The study further noted that 

air pollution control requirements in general had led to an 

estimated 37.5 to 45 percent increase in capital costs for coalfired power plant installation between 1971 and 1980.

272

The study retrospectively confirmed the EPA’s conclusion 

that imposition of these costs was reasonable, finding that 

“utilities with commitments to pollution control tend to fare no 

better and no worse than all electric utilities in general.”273

In assessing the capital cost impacts of the suite of 1970s EPA 

air pollution standards, the report concluded that “though 

controlling emissions is indeed costly, it has not played a 

major role in impairing the utilities’ financial position, and 

is not likely to do so in the future.”274

In NSPS standards for other sectors, the EPA's 

determination that capital cost increases were reasonable has 

 

270 Congressional Budget Office report, “The Clean Air Act, the 

Electric Utilities, and the Coal Market”, April 1982, p. 10-11, 

23.

271 Id. at 10-11.

272 Id. at 22.

273 Id. at xvi.

274 Id.
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similarly been upheld. In Portland Cement Association, the D.C. 

Circuit upheld the EPA’s consideration of costs for a standard 

of performance that would increase capital costs by about 12

percent, although the rule was remanded due to an unrelated 

procedural issue. 486 F.2d at 387-88. Reviewing the EPA’s final 

rule after remand, the court again upheld the standards and the 

EPA’s consideration of costs, noting that “[t]he industry has 

not shown inability to adjust itself in a healthy economic 

fashion to the end sought by the Act as represented by the 

standards prescribed.” Portland Cement v. Ruckelshaus, 513 F. 2d 

506, 508 (D.C. Cir. 1975).

The capital cost impacts incurred under these prior 

standards are comparable in magnitude on an individual unit 

basis to those projected for the present standard. We predict 

that the incremental costs of control for a new highly efficient 

SCPC unit to meet the final emission limitation of 1,400 lb 

CO2/MWh-g would be an increase of 21 - 22 percent for capital 

costs. See Table 7 below.275,276 

 

275 We explain at Section V.I.2 and 3 below the reasonableness of 

the EPA’s cost projections here.

276 We estimate that a new SCPC EGU using low rank coal 

(subbituminous coal or dried lignite) would incur a capital cost 

increase of 23 percent to meet the final standard. See 

“Achievability of the Standard for Newly Constructed Steam 

Generating EGUs” technical support document available in the 

rulemaking docket.
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Table 7. Comparison of Estimated Capital Costs for a New SCPC 

and a New SCPC Meeting the Final Standard of Performance.277

Total Total

Overnight As-Spent

Cost Capital

(2011$/kW) (2011$/kW)

SCPC - no CCS 2,507 2,842

SCPC - partial CCS 3,042 3,458

(1,400 lb CO2/MWh-g)

Incremental cost increase 21.3% 21.7%

By comparison, a SCPC that co-fires with natural gas to 

meet the final standard of 1,400 lb CO2/MWh-g would not result in 

an increase in capital cost over the uncontrolled SCPC. A 

compliant IGCC unit co-firing natural gas is predicted to have 

Total Overnight Cost of $3,036/kW – an approximately 21.1 

percent increase in capital over the uncontrolled SCPC unit.

5. Consideration of Costs Based on Levelized Cost of Electricity

As in the proposal, the EPA also considered the 

reasonableness of costs by evaluating the LCOE associated with 

the final standard. The LCOE is a commonly used economic metric 

that takes into account all costs to construct and operate a new 

power plant over an assumed time period and an assumed capacity 

factor. The LCOE is a summary metric, which expresses the full 

 

277 Exhibit A-3 (p. 18); “Cost and Performance Baseline for 

Fossil Energy Plants Supplement: Sensitivity to CO2 Capture Rate 

in Coal-Fired Power Plants”, DOE/NETL-2015/1720 (June 2015).
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cost of generating electricity on a per unit basis (i.e., 

megawatt-hours). Levelized costs are often used to compare the 

cost of different potential generating sources. While capital 

cost is a useful and relevant metric for capital-intensive

fossil-steam units, the LCOE can serve as a useful complement 

because it takes into account all specified costs (operation and 

maintenance, fuel – as well as capital costs), over the whole 

lifetime of the project. 

As previously mentioned, at proposal the EPA relied on LCOE 

projections for fossil fuel-fired EGUs (with and without CCS) 

from DOE/NETL reports detailing the results of studies 

evaluating the costs and performance of such units. For nonfossil dispatchable generating sources, the EPA relied on LCOE 

projections from EIA AEO 2013. For this final action, the EPA is 

relying on updated costs from the same sources. The NETL has 

provided updated cost and performance information in recently 

published revisions of reports used in the January 2014 

proposal.278 The updated SCPC cases in the reports include up-todate cost and performance information from recent vendor quotes 

 

278 “Cost and Performance Baseline for Fossil Energy Plants: 

Volume 1a” Bituminous Coal (PC) and Natural Gas to Electricity, 

Revision 3, U.S. DOE NETL report (2015) and “Cost and 

Performance Baseline for Fossil Energy Plants: Volume 1b: 

Bituminous Coal (IGCC) to Electricity, Revision 2 – Year Dollar 

Update, U.S. DOE NETL report (2015). Both reports are available 

at www.netl.doe.gov/research/energy-analysis/energy-baselinestudies.
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and implementation of the Shell Cansolv post-combustion capture 

process – the process that is currently being utilized at the 

Boundary Dam #3 facility. The IGCC cost and performance results 

in the updated reports utilize vendor quotes from the previous 

report; the costs are adjusted from $2007 to $2011. Important 

also to note is that DOE/NETL utilized conventional financing 

for cases without CCS and utilized high-risk financial 

assumptions for cases that include CCS.279

Using information from those reports, the DOE/NETL prepared 

a separate report summarizing a study that evaluated the cost 

and performance of various plants designed to meet a range of CO2

emissions by varying the CO2 capture rate (i.e., the level of 

partial capture).280 The EIA also updated LCOE projections from 

AEO 2013 to AEO 2014 and again in AEO 2015. Those are discussed 

in more detail in Section V.I.2.b and d. In evaluating costs for 

the final standards in this action, the EPA relied primarily on 

the updated NETL LCOE projections for new fossil fuel-fired EGUs 

provided in the reports described above and on the LCOE 

projections for non-fossil, dispatchable generating options from 

 

279 Cost and Performance Baseline for Fossil Energy Plants 

Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired Power 

Plants”, DOE/NETL-2015/1720 (June 2015) p. 18.

280 “Cost and Performance Baseline for Fossil Energy Plants 

Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired Power 

Plants”, DOE/NETL-2015/1720 (June 2015). Available at 

http://www.netl.doe.gov/research/energy-analysis/energybaseline-studies.
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the EIA’s AEO 2015.

281 Here, the EPA compared the LCOE of the 

final standard to the LCOE of analogous potential sources of 

intermediate and base load power. This comparison demonstrated 

that the LCOE for a fossil steam unit with partial CCS is within 

the range of the LCOE of comparable alternative non-NGCC 

generation sources. In particular, nuclear and biomass 

generation, which similarly provide both base load power and 

fuel diversity, have comparable LCOE. The EPA concludes that an

evaluation of the LCOE also demonstrates that the costs of the 

final standard are reasonable. 

a. Calculation of the LCOE

The LCOE of a power plant source is calculated with the 

expected lifetime and average capacity factor, and represents 

the average cost of producing a megawatt-hour (MWh) of 

electricity over the expected lifetime of the asset.

The LCOE incorporates all specified costs, and therefore is 

dependent on the project’s capital costs, the fixed and variable 

operating and maintenance (O&M) costs, the fuel costs, the costs 

to finance the project, and finally on the assumed capacity 

factor.282 The relative contribution of each of these inputs to 

LCOE will vary among the generating technologies. For example, 

 

281 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.

282 See, e.g. “Cost and Performance Baseline for Fossil Energy 

Plants Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired 

Power Plants”, DOE/NETL-2015/1720 (June 2015) at p. 17.
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the LCOE for a new supercritical PC plant or a new IGCC plant is 

influenced more by the capital costs (and thus the financing 

assumptions) and less on fuel costs than a comparably sized new 

NGCC facility which would require less capital investment but 

would be more influenced by assumed fuel costs.

b. Use of the LCOE

The utility industry and electricity sector regulators 

often use levelized costs as a summary measure for comparing the 

cost of different potential generating sources.

Use of the LCOE as a comparison measure is appropriate where the 

facilities being compared would serve load in a similar manner. 

The value of generation, as reflected in the wholesale 

electricity price, can vary seasonally and over the course of a 

day. In addition, electricity generation technologies differ on 

dimensions other than just cost, such as ramping efficiency, 

intermittency, or uncertainty in future fuel costs. These other 

factors are also important in determining the value of a 

particular generation technology to a firm, and accordingly cost 

comparisons between two different technologies are most 

appropriate and insightful when the technologies align along 

these other dimensions. Isolating a comparison of technologies 

based on their LCOE is appropriate when they can be assumed to 

provide similar services and similar values of electricity 

generated. 
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As we indicated in the proposal, we evaluated publicly 

available IRPs and other available information (such as public 

announcements) to determine the types of technologies that 

utilities are considering as options for new generating 

capacity.283 In the near future, the largest sources of new 

fossil fuel-fired power generation are expected to be new NGCC 

units. But the IRPs also suggested that utilities are interested 

in a range of technologies that can be used to provide or 

preserve fuel diversity within the utilities’ respective 

generating fleets.284,285 The options for dispatchable generation 

 

283 See also discussion at V.C.3 above. The IRPs do not provide 

an indication of the utility’s intention to pursue a particular 

generation technology. However, the IRPs do provide an 

indication of the types of new generating technologies that the 

utility would consider for new generating capacity.

284 See, e.g. the 2014 IRP of Dominion Virginia Power:

With those factors in mind, the 2014 Plan presents two paths 

forward for resource expansion: a Base Plan, designed using 

least-cost planning methods and consistent with the requirements 

of Rule R8-60 for utility plans to provide "reliable electric 

utility service at least cost over the planning period;" and a 

Fuel Diversity Plan, which includes a broader array of low or 

zero-emissions options. While the Fuel 2 Diversity Plan 

currently represents a higher cost option at today's current and 

projected commodity prices, its resource mix provides the 

important benefits of greater fuel diversity and lower carbon

intensity. Therefore, the Company will continue reasonable 

development of the more diverse and lower carbon intensive 

options in the Fuel Diversity Plan and will be ready to 

implement them as conditions warrant.... The Fuel Diversity Plan 

places a greater reliance on generation sources with little or 

no carbon emissions and is less reliant on natural gas. While 

following the resource expansion scenario in the least-cost Base 

Plan, the Company will continue evaluation and reasonable 
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development efforts for the following projects identified in the 

Fuel Diversity Plan. These include:

• Continued development of a third nuclear reactor at North Anna 

Power Station, using reactor technology supplied by GE-Hitachi 

Nuclear Energy Americas LLC. While the Company has made no final 

commitment to building this unit, it recognizes the many 

operational and environmental benefits of nuclear power and 

continues to actively develop the project. Our customers have 

benefitted from the existing nuclear fleet for many years now, 

and they will continue to benefit from the existing fleet for 

many years in the future. A final decision on construction of 

North Anna Unit 3 will not be made until after the Company 

receives a Combined Operating License or COL from the U.S. 

Nuclear Regulatory Commission, now expected in 2016. The Fuel 

Diversity Plan includes the addition of North Anna Unit 3's 

1,453 megawatts of zero-emissions generation by 2028. If 

constructed, the project would provide a dramatic boost to the 

regional economy.

• Additional reliance on renewable energy, including 247 

megawatts of onshore wind capacity at sites in western Virginia 

and a 12 megawatt offshore wind demonstration project by 2018.

• An additional 559 megawatts of nameplate solar capacity, 

including several new Company-owned photovoltaic CPV) 

installations. Solar PV costs have declined significantly in 

recent years, making utility-scale solar much more costeffective than distributed solar, and continuing technological 

development, in which the Company is participating, may allow it 

to become a more cost-effective source of intermittent 

generation in the future.” cover letter for 2014 IRP -

https://www.dom.com/library/domcom/pdfs/corporate/integratedresource-planning/va-irp-2014.pdf.

285 Another example are the recent statements of officials of 

Tri-State Generation and Transmission, available at 

http://www.wyofile.com/coal-power/, including:

“We are considering nuclear, coal and natural gas,” said Ken 

Anderson, general manager of Tri-State at a conference in 

October [2010], a position that Tri-State representatives say 

remains. “We will pick our technology once policy certainty 

comes about,” he added. ...Longer-term forecasts are based on 

assumptions that may or may not prove well-founded. Because of 
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that can provide intermediate or base-load power and fuel 

diversity would include new fossil steam units, new nuclear 

power, and biomass-fired generation. 

Thus, in both the proposal and in this final rule, the EPA 

is comparing the LCOE of technologies that would be reasonably 

anticipated to be designed, constructed, and operated for a 

similar purpose – that is, to provide dispatchable base load

power that provides fuel diversity by relying on a fuel source 

other than natural gas. In contrast, it may not be appropriate 

to compare the LCOE for a base load coal-fired plant with that 

of a peaking natural gas-fired simple cycle turbine. Similarly, 

it may not be appropriate to compare LCOE for dispatchable 

technologies (i.e., generating sources that can be ramped up or 

down as needed, e.g., coal-fired units, NGCC units, nuclear) 

with that of non-dispatchable technologies (i.e., generating 

 

this uncertainty, Tri-State believes it must retain options for 

all fuels and technologies.

“We will not take anything off the table,” [Tri-State spokesman 

Lee] Boughey said. That includes coal. “Coal is an affordable 

and plentiful resource, but it does come with challenges – and 

we are looking to different technology that can address some of 

those challenges while continuing to provide a reliable and 

affordable power supply,” Boughey said. “Some critics believe we 

shouldn’t be looking at resource options that include coal, and 

even nuclear technology,” Boughey added. “We believe it would be 

irresponsible not to consider these fuels or technologies as 

part of an affordable, reliable and responsible resource 

portfolio.”
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sources that cannot be reliably ramped up or down to meet 

demand, e.g., wind, solar.)

c. Reasonableness of costs based on LCOE

An examination of the LCOE of analogous sources of base 

load, dispatchable power shows that the final standard’s LCOE is 

comparable to that of other sources, as shown in Table 8 below.

As mentioned earlier and discussed in further detail below, 

these estimates rely most heavily on DOE/NETL cost projections 

for fossil fuel generating technologies and on the updated EIA 

AEO 2015 for non-fossil generation technologies. Recent 

estimates from Lazard286,287 are also provided for nuclear and 

biomass generation options.

Table 8. Predicted Cost and CO2 Emission Levels for a Range of 

Potential New Generation Technologies288

 

286 Lazard’s Levelized Cost of Energy Analysis – Version 8.0; 

September 2014; available at: 

http://www.lazard.com/media/1777/levelized_cost_of_energy_-

_version_80.pdf and in the rulemaking docket.

287 Lazard is one of the world's preeminent financial advisory 

and asset management firms. Lazard’s Global Power, Energy & 

Infrastructure Group serves private and public sector clients 

with advisory services regarding M&A, financing, and other 

strategic matters. The group is active in all areas of the 

traditional and alternative energy industries, including 

regulated utilities, independent power producers, advanced 

transportation technologies, renewable energy technologies, 

meters, smart grid and energy efficiency technologies, and 

infrastructure. http://www.marketwatch.com/story/lazardreleases-new-levelized-cost-of-energy-analysis-2014-09-18.

288 LCOE cost estimates for SCPC and IGCC cases come from “Cost 

and Performance Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants” 
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New Generation Emission LCOE*

Technology lb CO2/MWh-g $/MWh

SCPC - no CCS (bit) 1,620 76 - 95

SCPC – no CCS (low rank) 1,740 75 - 94

SCPC + ~16% partial CCS (bit) 1,400 92 - 117

SCPC + ~23% partial CCS (low rank) 1,400 95 - 121

Nuclear (EIA) 0 87 - 115

Nuclear (Lazard) 0 92 - 132

Biomass (EIA)289 - 94 – 113

Biomass (Lazard) - 87 - 116

IGCC 1,430 94 - 120

NGCC 1,000 52 – 86**

* The LCOE ranges presented in Table 8 include an uncertainty of 

-15%/+30% on capital costs for SCPC and IGCC cases and an 

uncertainty of -10%/+30% on capital costs for nuclear and 

biomass cases from EIA. This reflects information provided by 

EIA. Nuclear staff experts expect that nuclear plants currently 

under construction would not have capital costs under estimates 

and that one could expect to see a 30% “upside” variation in 

capital cost. There is also insufficient market data to get a 

 

DOE/NETL-2015/1720 (June 22, 2015). Cost and performance for low 

rank SCPC is adapted from “Cost and Performance Baseline for 

Fossil Energy Plants Volume 3 Executive Summary: Low Rank Coal 

and Natural Gas to Electricity”, DOE/NETL-2010/1399 (September 

2011). LCOE cost estimates for nuclear and biomass are derived 

from “Levelized Cost and Levelized Avoid Cost of New Generation 

Resources in the Annual Energy Outlook 2015”, June 2015, 

www.eia.gov/forecasts/aeo/pdf/electricity_generation.pdf. LCOE 

cost estimates for NGCC technology are EPA estimates based on a 

range of potential natural gas prices. 

289 Table 8 includes LCOE figures for biomass-fired generation, a 

potential sources of dispatchable base load power that is not 

fueled by natural gas. The EPA includes this information for 

completeness, while noting that biomass-fired units in operation 

in the U.S. are smaller scale and thus are not as robust 

analogues as nuclear power. CO2 emissions are not provided for 

biomass units because different biomass feedstocks have 

different net CO2 emissions; therefore a single emission rate is 

not appropriate to show in Table 8.
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good statistical range of potential capital cost variation (i.e. 

only 2 plants under construction, neither complete). The nuclear 

cost estimates from Lazard likewise reflect the range of 

expected nuclear costs. LCOE estimates displayed in this table 

for SCPC units with partial CCS as well as for IGCC units use a 

higher financing cost rate in comparison to the SCPC unit 

without capture.291

** This range represents a natural gas price from $5/MMBtu to 

$10/MMBtu.

As shown in Table 8, we project that the LCOE for new 

fossil steam capacity meeting the final 1,400 lb CO2/MWh-g

standard to be substantially similar to that for a new nuclear 

unit, the principal other alternative to natural gas to provide 

new base load power. This is the case for new units firing 

bituminous and subbituminous coals and dried lignite. This is 

another demonstration that the costs of the final standard are 

reasonable because nuclear and fossil steam generation each 

would serve an analogous role in adding dispatchable base load 

generation diversity – or at least non-NGCC alternatives - to a 

power provider’s portfolio; hence, they are reasonably viewed as 

comparable alternatives.292

As previously mentioned, the DOE/NETL assumed conventional 

financing for cases without CCS and assumed high-risk financing 

 

291 “Cost and Performance Baseline for Fossil Energy Plants 

Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired Power 

Plants”, DOE/NETL-2015/1720 (June 2015) at p. 18.

292 LCOE comparisons of reasonably available compliance 

alternatives – IGCC with natural gas co-firing, and SCPC with 

natural gas co-firing - are found below in Table 9. As shown 

there, these alternatives are either lower cost than SCPC with 

partial CCS, or of comparable cost.
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for cases with some level of CCS. Specifically a high-risk 

financial structure resulting in a capital charge factor (CCF) 

of 0.124 is used in the study to evaluate the costs of all cases 

with CO2 capture (non-capture case uses a conventional financial 

structure with a CCF of 0.116).293 As a comparison of how this 

affects the resulting DOE/NETL costs, a new SCPC utilizing 16 

percent partial CCS is projected to have an LCOE of $99/MWh 

(including transportation and storage costs; does not include 

the range for uncertainty). That projected LCOE includes the 

“high risk financial assumptions”. If the LCOE for that unit 

were to be calculated using the “conventional financing 

assumptions”, the resulting LCOE would be $94/MWh.

This approach is in contrast to that taken by the EIA which 

applies a 3-percentage-point cost of capital premium (the 

‘climate uncertainty adder’) to non-capture coal plants to 

reflect the market reaction to potential future GHG regulation.

Under current and anticipated market conditions, power 

providers that are considering costs alone in choosing a fuel 

source for new intermediate or base load generation will choose 

natural gas because of its competitive current and projected 

price. However, as noted in Section V.H.3, public IRPs indicate 

 

293 “Cost and Performance Baseline for Fossil Energy Plants 

Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired Power 

Plants”, DOE/NETL-2015/1720 (June 2015) at p. 7.
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that utilities are considering and selecting technologies that 

could provide or preserve fuel diversity within generating 

fleets. For example, utilities have been willing to pay a 

premium for nuclear power in certain circumstances, as indicated 

by the recent new constructions of nuclear facilities and by

IRPs that include new nuclear generation in their plans. In 

general, fossil steam and nuclear generation each can provide 

dispatchable, base load power while also maintaining or 

increasing fuel diversity.294 Utilities may be willing to pay a 

premium for these generation sources because they could serve as 

a hedge against the possibility that future natural gas prices 

will far exceed projected levels. Accordingly, the LCOE analysis 

demonstrates that the final standard’s costs are in line with 

power sources that provide analogous services – dispatchable 

base load power and fuel diversity. 

We further note a number of conservative elements of the 

costs we used in making this comparison. In particular, these 

estimates include the highest value in the projected range of 

potential costs for partial CCS. They do not reflect revenues 

 

294 As another example, San Antonio customers will benefit from 

low-carbon power from the Texas Clean Energy Project. CPS Energy 

CEO Doyle Deneby said in a news release: “Adding clean coal to 

our portfolio dovetails with our strategy to diversify and 

reduce the carbon intensity of the power we supply to our 

customers.” www.bizjournals.com/sanantonio/news/2014/10/06/cpsenergy-strikes-new-deal-to-buy-power-from.html.
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which can be generated by selling captured CO2 for enhanced oil 

recovery, and reflect the costs of partial CCS rather than 

potentially less expensive alternative compliance paths such as 

a utility boiler co-firing with natural gas. See also V.H.7 and 

8 below.

6. Overall Costs and Economic Impacts

As noted above, an assessment of national costs is also an 

appropriate means of evaluating the reasonableness of costs 

under CAA section 111. See Sierra Club, 657 F.2d at 330.

The EPA considered the regulation’s overall costs and 

economic impacts as part of its RIA. The RIA demonstrates that 

these costs would be negligible and that the effects on 

electricity rates and other market indicators would similarly be 

minimal.

These results are driven by the existing market context for 

fossil-steam generation. Even in the absence of the standards of 

performance for newly constructed EGUs, substantial new 

construction of uncontrolled fossil steam units is not 

anticipated under existing prevailing and anticipated future 

economic conditions. Modeling projections from government, 

industry, and academia anticipate that few new fossil steam EGUs 

will be constructed over the coming decade and that those that 
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are built would have CCS.295 Instead, EIA data shows that natural 

gas is likely to be the most widely-used fossil fuel for new 

construction of electric generating capacity in the near 

future.

296 Of the coal-fired units moving forward at various 

advanced stages of construction and development - Southern 

Company's Kemper County Energy Facility and Summit Power's Texas 

Clean Energy Project (TCEP) – each will deploy IGCC with some 

level of CCS. The primary reasons for this rate of current and 

projected future development of new coal projects include highly 

competitive natural gas prices, lower electricity demand, and 

increases in the supply of renewable energy. 

In its RIA, the EPA considered the overall costs of this 

regulation in the context of these prevailing market trends. 

Because of the expectation of no new fossil steam generation, 

the RIA projects that this final rule will result in negligible 

costs overall on owners and operators of newly constructed EGUs 

by 2022.298 More broadly, this regulation is not expected to have 

significant effects on fuel markets, electricity prices, or the 

 

295 RIA chapter 4. For example, even in the EIA’s sensitivity 

analysis that assumes higher natural gas prices and electricity 

demand, the EIA does not project any additional coal beyond its 

reference case until 2023, in a case where power companies 

assume no GHGs emission limitations, and until 2024 in a case 

where power companies do assume GHGs emission limitations. AEO 

2015.

296 Annual Energy Outlook 2010, 2011, 2012, 2013, 2014 and 2015.

298 Conditions in the analysis year of 2022 are represented by a 

model year of 2020.
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economy as a whole, as described in detail in Chapter 4 of the 

RIA.

In comparison, courts have upheld past regulations that 

imposed substantial overall costs in order to protect against 

uncontrolled emissions. As noted above, in Sierra Club v. 

Costle, the D.C. Circuit upheld a standard of performance that 

imposed costly controls on SO2 emissions from new coal-fired 

power plants. 657 F.2d at 410. These standards had implications 

for the economy “at the local and national levels,” as “EPA 

estimates that utilities will have to spend tens of billions of 

dollars by 1995 on pollution control under the new NSPS.” Id. at 

314. Further, the court acknowledged that “[c]onsumers will 

ultimately bear these costs, both directly in the form of 

residential utility bills, and indirectly in the form of higher 

consumer prices due to increased energy costs,” before 

concluding that the costs were reasonable. Id.

The projected total incremental capital costs associated 

with the standard we are finalizing in this rule are 

dramatically lower than was the case for this prior standard, as 

well as other prior standards summarized previously. For 

example, when the standard at issue in Sierra Club was upheld, 

the industry was expected to build, and did build, dozens of 

plants ultimately meeting the standards – at a projected 
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incremental cost of tens of billions of dollars.299 Here, by 

contrast, few if any fossil steam EGUs are projected to be built 

in the foreseeable future, indicating that the total incremental 

costs are likely to be considerably more modest. 

Commenters stated that the cost provision in CAA section 

111(a)(1) does not authorize the EPA to consider the nationwide 

costs of a system of emission reduction in lieu of considering 

the cost impacts for individual new plants. In this rule, we are 

considering both sets of costs and, in fact, we are not 

identifying full CCS as the BSER primarily for reasons of its 

cost to individual sources. At the same time, total projected 

costs are relevant in assessing the overall reasonableness of 

costs associated with a standard. Our analysis demonstrates that 

the impacts on the industry as a whole are negligible, and are 

certainly not greater than “what the industry could bear and 

survive.”300 These facts support the EPA’s overall conclusion 

that the costs of the standard are reasonable.

However, as noted earlier, for a variety of reasons, some 

companies may consider coal-fired steam generating units that 

the modeling does not anticipate. Thus, in Chapter 5 of the RIA, 

we also present an analysis of the project-level costs of a 

newly constructed coal-fired steam generating unit with partial 

 

299 Sierra Club, 657 F.2d at 314.

300 Portland Cement Ass’n, 513 F.2d at 508.
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CCS that meets the requirements of this final rule alongside the 

project-level costs of a newly constructed coal-fired unit 

without CCS. This analysis in RIA chapter 5 indicates that the 

quantified benefits of the standards of performance would exceed 

their costs under a range of assumptions. 

As required under Executive Order 12866, the EPA conducts 

benefit-cost analyses for major Clean Air Act rules, and has 

done so here. While such analysis can help to inform policy 

decisions, as permissible and appropriate under governing 

statutory provisions, the EPA does not use a benefit-cost test 

(i.e., a determination of whether monetized benefits exceed 

costs) as the sole or primary decision tool when required to

consider costs or to determine whether to issue regulations 

under the Clean Air Act, and is not doing so here.301 

Nonetheless, as just noted, the RIA analysis shows that the 

standard of performance has net quantified benefits under a 

range of assumptions. 

7. Opportunities to Further Reduce Compliance Costs

While the EPA believes, as detailed above, that there is 

sufficient evidence to show that the final standards of 

performance for new steam generating units can be met at a 

 

301 See Memorandum “Consideration of Costs and Benefits under the 

Clean Air Act” available in the rulemaking dockets, EPA-HQ-OAR2013-0495 (new sources) and EPA-OAR-HQ-2013-0603.
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reasonable cost, we also note that there are potential 

opportunities to further reduce compliance costs. We believe 

that, in most cases, the actual costs will be less than those 

presented earlier. 

As explained in more detail in the following subsection, a 

new utility boiler can meet the final standard of performance by 

co-firing with natural gas. Some project developers may choose 

to utilize natural gas co-firing as a means of delaying, rather 

than avoiding, implementation of partial CCS. Developers can 

also choose to install IGCC with a small amount of natural gas 

co-firing at costs within the range of SCPC with partial CCS, 

although slightly higher.

The EPA also notes that new units that capture CO2 will 

likely be built in areas where there are opportunities to sell 

the captured CO2 for some useful purpose prior to (or concomitant 

with) permanent storage. The DOE refers to this as “carbon 

capture, utilization and storage” or CCUS. In particular, the 

ability to sell captured CO2 for use in enhanced oil recovery 

operations offers the most opportunity to reduce costs. In this 

regard, the newly-operating Boundary Dam facility is selling 
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captured CO2 for EOR. The Kemper facility likewise plans to do 

so.302

In some instances, the costs of CCS may be defrayed by 

grants or other benefits provided by federal or state 

governments. The need for subsidies to support emerging energy 

systems and new control technologies is not unusual. Each of the 

major types of energy used to generate electricity has been or 

is currently being supported by some type of government subsidy 

such as tax benefits, loan guarantees, low-cost leases, or 

direct expenditures for some aspect of development and 

utilization, ranging from exploration to control installation. 

This is true for fossil fuel-fired, as well as nuclear-,

geothermal-, wind-, and solar-generated electricity.

As stated earlier, the EPA considers the costs of partial CCS at 

a level to meet the final standard of performance to be 

reasonable even without considering these opportunities to 

further reduce implementation and compliance costs. We did not 

in the proposal – and we do not here in this final action – rely 

on any cost reduction opportunities to justify the costs of 

meeting the standard as reasonable, but again note the 

 

302 The EPA is referring to the Kemper facility here as an 

example of how costs can be defrayed, not for use of technology 

or level of emission reduction achieved. The EPA therefore does 

not believe that the EPAct05 prevents reference to the fact that 

Kemper plans to sell captured carbon.
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conservative assumptions embodied in our assessment of 

compliance costs.

a. Cost and feasibility of natural gas co-firing as an 

alternative compliance pathway

Although the EPA has determined that implementation of 

partial CCS at an emission limitation of 1,400 lb CO2/MWh-g is 

the BSER for newly constructed fossil fuel-fired steam 

generating EGUs, we also note that operators can consider the 

use of natural gas co-firing to achieve the final emission 

limitation, likely at a lower cost.

At the final emissions limitation of 1,400 lb CO2/MWh-g a 

new supercritical PC or supercritical CFB can meet the standard 

by co-firing with natural gas at levels up to approximately 40 

percent (heat input basis) and could potentially avoid (or 

delay) installation and use of partial CCS altogether.

Natural gas co-firing has long been recognized as an option 

for coal-fired boilers to reduce emissions of criteria and 

hazardous air pollutants. EPRI sponsored a study to assess both 

technical and economic issues associated with natural gas cofiring in coal-fired boilers.

304 They determined that the largest 

number of applications and the longest experience time is with 

 

304 Gas Cofiring Assessment for Coal Fired Utility Boilers; Final 

Report, August 2000; EPRI Technical Report available at 

www.epri.com.
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natural gas reburning and with supplemental gas firing. Natural 

gas reburning has been used primarily as a NOX control

technology. It is implemented by introducing natural gas (up to 

20 percent total fuel heat input) in a secondary combustion zone 

(called the “reburn zone”) downstream of the primary combustion 

zone in the boiler. Injecting the natural gas creates a fuelrich zone where NOX formed in the main combustion zone is reduced 

to nitrogen and water vapor. 

Higher levels of natural gas co-firing can be met by 

utilizing supplemental gas co-firing (either alone or along with 

natural gas reburning). This involves the simultaneous firing of 

natural gas and pulverized coal in a boiler’s primary combustion 

zone. Others have also evaluated configurations that would allow 

coal-fired units to utilize natural gas.305,306

A 2013 article entitled “Utility Options for Leveraging 

Natural Gas”307 noted that: 

 

305 Many of the studies evaluated opportunities to use natural 

gas reburn, natural gas co-firing and other configurations in 

existing coal-fired boilers. Those conclusions would also be 

applicable for new coal-fired boilers. 

306 “Dual Fuel Firing – The New Future for the Aging U.S. Based 

Coal-Fired Boilers”, presented by Riley Power, Inc. at 37th 

International Technical Conference on Clean Coal and Fuel 

Systems June 2012 Clearwater, FL, available at 

http://www.babcockpower.com/pdf/RPI-TP-0228.pdf. 

307 Utility Options for Leveraging Natural Gas, 10/01/2013 

article in Power. Available at http://www.powermag.com/utilityoptions-for-leveraging-natural-gas/.
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Utility owners of coal-fired power stations that 

wish to balance their exposure to coal-fired 

generation with additional natural gas–fired 

generation have several options to consider. The four 

most practical options are co-firing coal and gas in 

the same boiler, converting the coal-fired boiler to 

gas-only operation, repowering the coal plant with 

natural gas–fired combustion turbines, or replacing 

the coal plant with a combined cycle plant. [...] Cofiring is the lowest-risk option for substituting gas 

use for coal. 

The EPA examined compliance costs for a new steam 

generating unit to meet the final standard of performance using 

natural gas co-firing and compared those costs to the estimated 

costs of meeting the final standards using partial CCS. Those 

costs are provided below in Table 9.

Table 9. Predicted Costs to Meet the Final Standard Using 

Natural Gas Co-firing.308

New Generation Emission LCOE

Technology lb CO2/MWh-g $/MWh

SCPC - no CCS 1,620 82

SCPC + ~16% partial CCS 1,400 99

SCPC + ~34% NG co-fire 1,400 92

IGCC - no CCS 1,434 103

IGCC + ~6% NG co-fire 1,400 105

NGCC* 1,000 60

* The generation cost using NG co-fire and NGCC assume a natural 

gas price of $6.19/mmBtu.

 

308 Costs and emissions for cases that do not utilize natural gas 

co-firing are from “Cost and Performance Baseline for Fossil 

Energy Plants Supplement: Sensitivity to CO2 Capture Rate in 

Coal-Fired Power Plants”, DOE/NETL-2015/1720 (June 2015). Costs 

and emissions for natural gas co-fired cases are EPA estimates.
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The EPA thus again notes that the cost assumptions it is 

making in its BSER determination are conservative. That is, by 

costing partial CCS as BSER, the EPA may be overestimating 

actual compliance costs since there exist other less expensive 

means of meeting the promulgated standard.309

Notwithstanding that costs for a SCPC to meet the standard 

would be lower if it co-fired with natural gas, we have not 

identified that compliance alternative as BSER because we 

believe that new coal-fired steam electric generating capacity 

would be built to provide fuel diversity, and burning 

substantial amounts of natural gas would be contrary to that 

objective. In addition, this choice would not promote use of 

advanced pollution control technology. New IGCC has costs which 

are comparable to SCPC, as does IGCC with natural gas cofiring,310 but we are choosing not to identify it as BSER for 

reasons stated at Sections V.C.2 and V.P: use of IGCC does not 

advance emission control beyond current levels of performance 

 

309 Certain commenters argued that the proposed standard 

essentially mandated a sole method of compliance, and hence 

constituted a work practice for purposes of section 111(h) of 

the Act. These commenters argued further that the EPA had failed 

to justify the proposal under the section 111(h) criteria. The 

EPA disagrees with the premise of these comments, but, in any 

case, there are clearly multiple compliance paths available for 

achieving the final standard.

310 IGCC units already have combined cycle capacity, and so can 

be readily operated in whole or in part using natural gas as a 

fuel. Indeed, both the Edwardsport and Kemper IGCC facilities 

have operated at times by firing exclusively natural gas.
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for sources which may choose to utilize IGCC technology. 

Nonetheless, use of IGCC remains a viable, demonstrated

compliance option to meet the 1,400 lb CO2/MWh-g standard of 

performance, and is available at reasonable cost and (as shown 

at Section V.P below) without significant adverse non-air 

quality impacts or energy implications.

b. Costs are reasonably expected to decrease over time

The EPA reasonably expects that the costs of CCS will 

decrease over time as the technology becomes more widely 

deployed. Although, for the reasons that have been noted, we 

consider the current costs of CCS to be reasonable, the 

projected decrease in those costs further supports their 

reasonableness. The D.C. Circuit case law that authorizes 

determining the “best” available technology on the basis of 

reasonable future projections supports taking into account 

projected cost reductions as a way to support the reasonableness 

of the costs.

We expect the costs of CCS technologies to decrease for 

several reasons. We expect that significant additional knowledge 

will be gained from deployment and operation of the new coalfired generation facilities that are either operating or are 

nearing completion. These would include the Boundary Dam Unit #3 

facility, the Petra Nova WA Parish project, and the Kemper 

County IGCC facility. The operators of the Boundary Dam Unit #3 
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are considering construction of additional CCS units and have 

projected that the next units could be constructed at a cost of 

at least 30 percent less than that at Unit #3.311 These savings 

primarily come from application of lessons learned from the Unit 

#3 design and construction. 

To facilitate the transfer of the technology and to 

accelerate development of carbon capture technology, SaskPower 

has created the CCS Global Consortium.312 This consortium 

provides SaskPower the opportunity to share the knowledge and 

experience from the Boundary Dam Unit #3 facility with global 

energy leaders, technology developers, and project developers. 

SaskPower, in partnership with Mitsubishi and Hitachi, is also 

helping to advance CCS knowledge and technology development 

through the creation of the Shand Carbon Capture Test Facility 

(CCTF).313 The test facility will provide technology developers 

with an opportunity to test new and emerging carbon capture 

systems for controlling carbon emissions from coal-fired power 

plants.

The DOE also sponsors testing at the National Carbon 

Capture Center (NCCC). The NCCC – located at Southern Company’s 

 

311 “Boundary Dam – The Future is Here”, plenary presentation by 

Mike Monea at the 12th International Conference on Greenhouse Gas 

Technologies (GHGT-12), Austin, TX (October 2014).

312 http://www.saskpowerccs.com/consortium/.

313 www.saskpowerccs.com/ccs-projects/shand-carbon-capture-testfacility/.
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Plant Gaston in Wilsonville, AL – provides first-class 

facilities to test new capture technologies for extended periods 

under commercially representative conditions with coal-derived 

flue gas and syngas.314

We expect continued additional cost reductions to come from 

knowledge gained from continued operation of non-power sector 

industrial projects which, as we have discussed, are informative 

in transferring the technology to power sector applications. We 

expect the on-going research and development efforts – such as 

those sponsored by the DOE/NETL.

Significant reductions in the cost of CO2 capture would be 

consistent with overall experience with the cost of pollution 

control technology. Reductions in the cost of air pollution 

control technologies as a result of learning-by-doing, 

reductions in financial premiums related to risk, research and 

development investments, and other factors have been observed 

over the decades.

c. Opportunities to reduce cost through sales of captured CO2

Geologic storage options include use of CO2 in EOR

operations, which is the injection of fluids into a reservoir 

after production yields have decreased from primary production 

in order to increase oil production efficiency. CO2-EOR has been 

 

314 www.nationalcarboncapturecenter.com/index.html.
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successfully used for decades at many production fields 

throughout the U.S. to increase oil recovery. The use of CO2 for 

EOR can significantly lower the net cost of implementing CCS. 

The opportunity to sell the captured CO2 for EOR, rather than 

paying directly for its long-term storage, improves the overall 

economics of the new generating unit. According to the 

International Energy Agency (IEA), of the CCS projects under 

construction or at an advanced stage of planning, 70 percent 

intend to use captured CO2 to improve recovery of oil in mature

fields.315 See also Section V.M.3 below.

I. Key Comments Regarding the EPA’s Consideration of Costs

In its consideration of the costs associated with the final 

standard, the EPA considered a range of different cost metrics, 

each with its individual strengths and weaknesses. As discussed 

above, each metric supports the EPA’s conclusion that the costs 

of the final standard are reasonable.

In this section, we review the comments received on 

assessing cost reasonableness and specific cost metrics. We 

explain how these comments informed our consideration of 

different metrics and cost reasonableness in general. 

 

315 Tracking Clean Energy Progress 2013, International Energy 

Agency (IEA), Input to the Clean Energy Ministerial, OECD/IEA 

2013.
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1. Use of LCOE as a Cost Metric

As noted, CAA section 111(a) directs the EPA to consider 

“cost” in determining if the BSER is adequately demonstrated. It 

does not provide further guidance as to how costs are to be 

considered, thus affording the EPA considerable discretion to 

choose a reasonable means of cost consideration. See, e.g. 

Lignite Energy Council v. EPA, 198 F. 3d at 933. Certain 

commenters nonetheless argued that LCOE was an impermissible 

metric because it does not measure the cost of achieving the 

emission reduction, but rather measures the impact on the 

product produced by the entity subject to the standard.316 The 

EPA does not agree that its authority is so limited. Indeed, in 

the first decided case under section 111, the D.C. Circuit, in 

holding that the EPA’s consideration of costs was reasonable, 

specifically noted the EPA’s examination of the impact of the 

standards on the regulated source category’s product in 

comparison to competitive products. Portland Cement Ass’n v. 

EPA, 486 F. 2d at 388 (“costs of control equipment could be 

passed on without substantially affecting competition with 

construction substitutes such as steel, asphalt, and aluminum”).

Commenters also argued that the choice of LCOE as a cost 

metric masked consideration of the considerable capital costs 

 

316 Comments of EEI, pp 94-5.
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associated with CCS. The EPA disagrees with this contention. The 

LCOE does not mask consideration of capital costs. Rather, as 

explained at V.H.5 above, LCOE is a summary metric that 

expresses the full cost (e.g., capital, O&M, fuel) of generating 

electricity and therefore provides a useful summary metric of 

costs per unit of production (i.e., megawatt-hours). Provided 

that those megawatt-hours provide similar electricity services 

and align on dimensions other than just cost, then the LCOE 

provides a useful comparison of which technologies are least 

cost.

The EPA certainly does not minimize that project developers 

must take capital costs into consideration, and as discussed in 

Section V.H.4 above, the EPA accordingly has considered direct 

capital costs here as part of its assessment and found those 

costs to be reasonable. In addition, the EPA notes that its 

comparison of the marginal impacts from an individual 

illustrative facility’s compliance with the standard, discussed 

in detail above and in the RIA Chapter 5, took into account the 

marginal capital costs that would be incurred by an individual 

facility. 

According to EIA317, capital costs represent approximately

63 percent of the LCOE for a new coal-fired SCPC plant; 

 

317 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.
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approximately 66 percent of the LCOE for a new IGCC plant; 

approximately 74 percent of the LCOE for a new nuclear plant; 

and only about 22 percent of the LCOE for a new NGCC unit. The 

LCOE of a new NGCC unit is much more strongly affected by fuel 

costs (natural gas). As we have discussed in detail in this 

preamble, in the preamble for the January 2014 proposal, and in 

associated technical support documents, the power sector has 

moved toward increased use of natural gas for a variety of 

reasons. If capital was the only cost that utilities and project 

developers considered, then they would almost certainly always 

choose to build a new NGCC unit. However, a variety of factors 

can be involved in selecting a generation source beyond capital 

costs. Accordingly, in considering cost reasonableness the EPA

considered metrics that encompassed other costs as well as the 

value of fuel and fleet diversity. 

Some commenters maintained that even if LCOE was a proper 

cost metric, the comparison with the costs of a new nuclear 

power plant is improper because nuclear itself is a highly 

expensive technology. The EPA disagrees. The comparison is 

appropriate and valid because, as discussed at V.H.3 above, 

under current and foreseeable economic conditions affecting the 

cost of new fossil steam generation and new nuclear generation 

relative to the cost of new natural gas generation, neither new 

nuclear power nor fossil steam generation are competitive with 
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new natural gas if evaluated on the basis of LCOE alone. 

Nonetheless, both are important potential alternatives to 

natural gas power for those interested in dispatchable base load

power that maintains or increases fuel diversity. As shown in a 

survey of recent IRP filings in the docket318 and Section II.C.5 

above, several utilities are considering new nuclear power as a 

potential generation option. Because both fossil steam and 

nuclear generation serve a comparable role of offering a diverse 

source of base load power generation, the EPA concludes that the 

comparison of their LCOE is a valid approach to evaluating cost 

reasonableness.

2. Use of Cost Estimates from DOE/NETL and DOE/EIA

In the January 2014 proposal, the EPA relied mostly on the 

cost projections for new fossil fuel-fired generating sources 

that were informed by cost studies conducted by DOE/NETL. The 

EPA relied on the EIA’s AEO 2013 projections for non-fossil 

based generating sources (i.e., nuclear, renewables, etc.). For 

this final rule, the EPA continues to rely most heavily on 

DOE/NETL cost projections for fossil fuel generating 

technologies and on the updated DOE/EIA AEO 2014 for nuclear and 

other base load non-fossil generation technologies.

 

318 Technical Support Document - “Review of Electric Utility 

Integrated Resource Plans” (May 2015), available in the 

rulemaking docket EPA-HQ-OAR-2013-0495.
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a. DOE/NETL cost and performance studies

The DOE/NETL “Cost and Performance Baselines for Fossil 

Energy Plants” are a series of studies conducted by NETL to 

establish estimates for the cost and performance of combustion 

and gasification based power plants with and without CO2 capture 

and storage.319 The studies evaluate numerous technology 

configurations utilizing different coal ranks and natural gas. 

The EPA relied on those sources because the NETL studies 

are the most comprehensive and transparent of the available cost 

studies and NETL has a reputation in the power sector industry 

for producing high quality, reliable work.320 The NETL studies 

were extensively peer reviewed.321 The EPA Science Advisory Board 

Work Group considering the adequacy of the peer review noted the 

EPA staff’s statement that “the NETL studies were all peer 

reviewed under DOE peer review protocols”, further noted the EPA 

staff’s statement that “the different levels of review of these 

DOE documents met the requirements to support the analyses as 

 

319 http://www.netl.doe.gov/research/energy-analysis/energybaseline-studies.

320 The NETL costs and studies are often cited in academic and 

other publications.

321 The initial NETL study “Cost and Performance Baseline for 

Fossil Energy Plants, Vol. 1: Bituminous Coal and Natural Gas to 

Electricity” (2006) was subject to peer review by industry 

experts, academia, and government research and regulatory 

agencies. Subsequent iterations of the study were not further 

peer reviewed because the modeling procedures used in the cost 

estimation were not revised.
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defined by the EPA Peer Review Handbook,” and concluded that 

“peer review on the DOE documents” was conducted “at a level 

required by agency guidance.”322

The cost estimates were indicated by DOE/NETL to carry an 

accuracy of -15 percent to +30 percent on the capital costs, 

consistent with a AACE Class 4 cost estimate – i.e., a 

“feasibility study” level of design engineering.323 The DOE/NETL 

further notes that “The value of the study lies not in the 

absolute accuracy of the individual case results but in the fact 

that all cases were evaluated under the same set of technical 

and economic assumptions. This consistency of approach allows 

meaningful comparisons among the cases evaluated.”

324

For the final standard, the EPA made particular use of the 

most recent NETL cost estimates for post-combustion CCS, which 

 

322 Letter from James Mihelcic, Chair, SAB Work Group on EPA 

Planned Actions for SAB Consideration of the Underlying Science 

to Members of the Chartered SAB and SAB Liaisons (page 3, Jan. 

24, 2014).

http://yosemite.epa.gov/sab/sabproduct.nsf/F43D89070E89893485257

C5A007AF573/$File/SAB+work+grp+memo+w+attach+20140107.pdf. 

The SAB’s statement that these guidance documents “require” any 

specific peer review is an overstatement, since guidance 

documents, by definition, do not mandate any specific course of 

action.

323 Recommended Practice 18R-97 of the Association for the 

Advancement of Cost Engineering International (AACE) describes a 

Cost Estimate Classification System as applied in Engineering, 

Procurement and Construction for the process industries.

324 “Cost and Performance Baseline for Fossil Energy Plants 

Volume 1: Bituminous Coal and Natural Gas to Electricity” Rev 2a 

(Sept 2013); DOE/NETL-2010/1397, page 9.
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reflect up-to-date vendor quotes and incorporate the postcombustion capture technology – the Shell Cansolv amine-based 

process – that is being utilized at the Boundary Dam Unit #3 

facility.325 The EPA used this latest version of the NETL studies 

not only to assure that it considers the most up-to-date 

information but also to address public comments criticizing the 

proposal for relying on out-of-date cost information. 

b. Other studies that corroborate NETL cost estimates

A variety of government, industry and academic groups 

routinely conduct studies to estimate costs of new generating 

technologies. These studies use techno-economic models to 

predict the cost to build a new generating facility at some 

point in the future. These studies often use levelized cost of 

electricity (LCOE) to summarize costs and to compare the 

competiveness of the different generating technologies. 

A variety of groups have recently published LCOE estimates 

for new dispatchable generating technologies. Those are shown 

below in Table 10. The table shows LCOE projections from the 

EPA’s January 2014 proposal, from studies conducted by the 

 

325 Cost and Performance Baseline for Fossil Energy Plants Volume 

1a: Bituminous Coal (PC) and Natural Gas to Electricity, 

Revision 3, July 6, 2015, DOE/NETL-2015/1723. 
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Electric Power Research Institute (EPRI)326, by the DOE’s Energy 

Information Administration (EIA) in their 2015 Annual Energy 

Outlook (AEO 2015), by the DOE’s National Energy Technology 

Laboratory (NETL), and by researchers from the Department of 

Engineering and Public Policy at the Carnegie Mellon University 

(CMU) in Pittsburgh, PA.

The Global CCS Institute327 has recently published a report 

that examines costs of major low and zero emissions technologies 

currently available for power generation and compares the 

predicted LCOEs of those technologies. Importantly, the analysis 

presented in the report uses cost and performance data from 

several recent studies, and applies a common methodology and 

economic parameters to derive comparable lifetime costs. 

Analysis and findings in the paper reflect costs specific to the 

U.S. 

The fact that these various groups have conducted 

independent studies and that the results of those independent 

studies are reasonably consistent with the estimates of DOE/NETL

are further indications that the DOE/NETL cost estimates are 

reasonable.

 

326 EPRI is a non-profit organization, headquartered in Palo 

Alto, CA, that conducts research on issues related to the U.S. 

electric power industry (www.epri.com).

327 www.globalccsinstitute.com.
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Table 10. Selection of Levelized Cost of Electricity (LCOE) Projections 

New Generation Lazard328 EPRI329 AEO2015330 DOE/NETL

331

CMU

332 GCCSI333*

*

Technology $2014/MWh $2011/MW

h

$2013/MWh* $2011/MWh

*

$2010/MW

h

$2014/MW

h

SCPC – no CCS 66 62 – 77 95 76 – 95 59 78

SCPC - full CCS 151 102 –

137

- 140 – 176 - 115 -

160

SCPC - 16% CCS - - - 92 - 117 - -

Nuclear*** 92 – 132 85 – 97 87 – 115 - - 86 - 102

Biomass 87 – 116 90 – 155 94 – 113 - - 123 -

137

IGCC 102 82 – 96 116 94 – 120 - -

 

328 Lazard’s Levelized Cost of Energy Analysis – Version 8.0 (Sept 2014); available at 

http://www.lazard.com/media/1777/levelized_cost_of_energy_-_version_80.pdf and in the 

rulemaking docket.

329 "Program on Technology Innovation: Integrated Generation Technology Options 2012; 

Report 1026656; Available at: www.epri.com.

330 “Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual 

Energy Outlook 2015”, Available at: www.eia.gov/forecasts/aeo/electricity_generation.cfm; 

the LCOE values displayed incorporate -10%/+30% for uncertainty for biomass and nuclear.

331 “Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO2

Capture Rate in Coal-Fired Power Plants” DOE/NETL-2015/1720 (June 22, 2015). 

332 CMU is Carnegie Mellon University; Zhai, H., Rubin, E.; “Comparative Performance and 

Cost Assessments of Coal- and Natural Gas-Fired Power Plants under a CO2 Emission 

Performance Standard Regulation”, Energy & Fuels, 2013, 27, 4290, Table 1.

333 “The Costs of CCS and other Low-Carbon Technologies - 2015 update” July 2015, Global 

CCS Institute, Available at: 

http://hub.globalccsinstitute.com/sites/default/files/publications/195008/costs-ccsother-low-carbon-technologies-2015-update.pdf.
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IGCC - full CCS 171 105 –

136

144 142 – 178 - -

NGCC 61 – 87 33 – 65 73 58 63 60

* EIA, in cost projections for SCPC and IGCC with no CCS, includes a climate uncertainty 

adder (CUA), which is a 3-percentage point increase in the cost of capital. In contrast, 

DOE/NETL utilized conventional financing for cases without CCS and utilized high-risk 

financial assumptions for cases that include CCS.

** The Global CCS Institute provided range for coal with full CCS (shown as “CCS(coal)” 

in Figure 5.2 of the referenced report) reflects a combination of costs for both PC and 

IGCC coal plants.

*** EIA AEO assumes use of Westinghouse AP1000 technology. Other groups assume a wider 

range of technology options.
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The LCOE values from the Lazard, EPRI, and NETL studies are 

presented as a range. The EPRI costs incorporate uncertainty 

reflecting the range of inputs (i.e., capital costs, fuel costs, 

fixed and variable O&M, etc.). The NETL costs are indicated to 

carry an accuracy of -15 percent to + 30 percent, consistent 

with a “feasibility study” level of design. The range in Table 

10 is the NETL projected costs with the -15 percent to +30 

percent uncertainty on the capital costs. Overall, as can be 

seen from the results in Table 10, the range of LCOE estimates 

from the different groups are in reasonable agreement with the 

DOE/NETL estimates most often representing the most conservative 

of the estimates shown.

The EIA cost estimates include a climate uncertainty adder 

(CUA) – represented by a three percent increase to the weighted 

average cost of capital — to certain coal-fired capacity types. 

The EIA developed the CUA to address inconsistencies between 

power sector modeling absent GHG regulation and the widespread 

use of a cost of CO2 emissions in power sector resource planning.

The CUA reflects the additional planning cost typically assigned 

by project developers and utilities to GHG-intensive projects in 

a context of climate uncertainty. The EPA believes the CUA is 

consistent with the industry’s planning and evaluation framework 

(demonstrable through IRPs and PUC orders) and is therefore 

pertinent when evaluating the cost competitiveness of 
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alternative generating technologies. The EPA believes the CUA is 

relevant in considering the range of costs that power companies 

are willing to pay for generation alternatives to natural gas.

c. Industry information that corroborates NETL cost estimates

Information from vendors of CCS technology also supports 

the reliability of the cost estimates the EPA is using here.334 

Specifically, the EPA had conversations with representatives 

from Summit Carbon Capture, LLC regarding available cost 

information. Cost estimates provided by another leading provider 

of CCS technology likewise are consistent (indeed, somewhat less 

than) the estimates the EPA is using for purposes of cost 

analysis in the rule.

Summit Carbon Capture’s primary business is large-scale 

carbon capture from power and other industrial projects and use 

of the captured CO2 for EOR.335 Summit is actively working with 

several different technology companies offering CO2 capture 

systems, including the leading equipment manufacturers for 

fossil fuel power production equipment. Their current projects 

include the 400 MW IGCC Texas Clean Energy Project and the 

Caledonia Clean Energy Project – a new project underway in the 

 

334 See Section V.F above, explaining that the D.C. Circuit has 

repeatedly stated that vendor statements are probative in 

demonstrating that a technology is adequately demonstrated under 

section 111.

335 http://www.summitpower.com/projects/carbon-capture/.
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United Kingdom – and a variety of other projects under 

development which are not yet public.

Summit is also interested in potentially retrofitting CCS 

onto existing coal-fired plants for the purpose of capturing CO2

for sale to EOR markets. Summit provided the EPA with copies of 

slides from a presentation that it has used in different public 

forums.336 The presentation focused on costs to retrofit 

available carbon capture equipment at an existing PC power plant 

that is ideally located to take advantage of opportunities to 

sell captured CO2 for use in EOR operations. Summit received 

proprietary costing information from numerous technology 

providers and that information, along with other publically 

available information, was used to develop their cost 

predictions.337 Though the primary focus of their effort was to 

examine costs associated with retrofitting CCS to an existing 

coal fired power plant, Summit Power also calculated costs for 

several new generation scenarios – including the cost of a new 

NGCC, a new SCPC, a new SCPC with full CCS, and a new SCPC with 

partial CCS at 50 percent. The costs are reasonably consistent 

 

336 “Coal’s Role in a Low Carbon Energy Environment”, presented 

at 2015 Euromoney Power & Renewables Conference, remarks by 

Jeffrey Brown (amended to address EPA questions on the 

original). Available in the rulemaking docket.

337 No proprietary or business confidential information was 

shared with the EPA. No specific vendors were mentioned by name 

during discussions with Summit Power. Summit also used available 

DOE/NETL and EIA cost information.
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with costs predicted by NETL, EIA, EPRI and others. The company 

ultimately concluded that “in a world of uncertain gas prices, 

falling CO2 capture equipment prices, improving CCS process 

efficiency, and possible compliance costs ... existing coal plants 

retrofitted with available CCS equipment can be cost competitive 

with development of new NGCC generation.”338

In June 2012, Alstom Power released a report entitled “Cost 

assessment of fossil power plants equipped with CCS under 

typical scenarios”.339, The study examined costs for a new coalfired power plant implementing post-combustion CCS (full CCS) in 

Europe, in North America, and in Asia. The results for the North 

American case – along with similar cost estimates from Summit –

are shown in Table 11 below. The DOE/NETL estimated costs are 

also included for comparison. The results show predicted costs 

for a new SCPC ranging from $53/MWh to $82/MWh and costs to 

implement full CCS ranging from $97/MWh to $143/MWh. Costs to 

 

338 Others have come to similar conclusions – that retrofit of 

CCS technology at existing coal-fired power plants can be 

feasible – e.g., “The results indicate that for about 60 

gigawatts of the existing coal-fired capacity, the 

implementation of partial CO2 capture appears feasible, though 

its cost is highly dependent on the unit characteristics and 

fuel prices.” (Zhai, H.; Ou, Y.; Rubin, E.S.; “Opportunities for 

Decarbonizing Existing U.S. Coal-fired Plants via CO2 Capture, 

Utilization, and Storage”, accepted for publication in Env. Sci 

& Tech. (2015).

339 Leandri, J., Skea, A., Bohtz, C., Heinz, G.; “Cost assessment 

of fossil power plants equipped with CCS under typical 

scenarios”, Alstom Power, June 2012. Available in the rulemaking 

docket: EPA-HQ-OAR-2013-0495.
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implement varying levels of partial CCS are also provided for 

comparison. The industry cost estimates are on the lower end of 

the range of costs predicted from other techno-economic studies 

(see Table 11 below) and, like those economic studies, are 

affected by the specific assumptions. As with the techo-economic 

studies presented earlier in Table, there is relatively good 

agreement among these projected costs and the DOE/NETL costs. 

There is relatively good agreement in the incremental levelized 

cost to implement full CCS on the new SCPC units (ranging from 

74 to 85 percent) and to implement 50 percent CCS on the new 

SCPC unit (from 41 to 45 percent increase). These industry 

estimates are also lower than the DOE/NETL estimates for both 

full and 50 percent partial CCS (with the incremental cost 

percentage for full CCS being almost identical), providing 

further support for the reasonableness of the EPA using the NETL 

cost estimates here.

Table 11. Industry LCOE Estimates for Implementation of PostCombustion CCS340

 

340 Note that in other tables in this preamble, the EPA has 

presented LCOE values from the DOE/NETL work as a range in order 

to incorporate the uncertainty on the capital costs. The range 

is not present here for easy comparison with the industry costs 

which were not provided as a range. The full range of DOE/NETL 

costs for each of the cases presented can be found in Exhibit A3 in “Cost and Performance Baseline for Fossil Energy Plants 

Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired Power

Plants”, DOE/NETL-2015/1720 (June 2015), p. 18.
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Summit Alstom DOE/NETL

$/MWh $/MWh* $/MWh

SCPC 64.5 52.6 82.3

SCPC + full CCS 117.6 97.4 152.4

Full CCS incremental cost, % 82.3% 85.0% 85.2%

SCPC + 50% CCS 91.1 - 123.6

50% CCS incremental cost, % 41.2% - 50.1%

SCPC + 35% CCS - - 114.7

SCPC + 16% CCS - - 100.5

NGCC** 47.7 35.0 52.0**

* Costs are from Figure 2 in the referenced Alstom report (North 

American case); costs are presented as €/MWh in the report. The 

costs were converted to $/MWh assuming a conversion rate of 1 

USD = 0.76 € (in 2012).

** NGCC cost is estimated by the EPA using NETL information.

Assumed natural gas prices = Summit ($4/mmBtu); Astom 

($3.9/mmBtu); EPA ($5.00/mmBtu).

The EPA notes that in its public comments, Alstom 

maintained that “no CCS projects that would [sic] be considered 

cost competitive in today’s energy economy.”341 As explained 

above, no steam electric EGU would be cost competitive even 

without CCS – and that is substantiated in the projected costs 

presented above in Table 11 where NGCC is consistently the most 

economic new generation option when compared to the other listed 

technologies. Alstom does not explain (or address) why the cost 

premium for partial CCS would be a decisive deterrent for 

 

341 Alstom Comment p. 3. The comment also urged the EPA to 

evaluate costs without considering EOR opportunities (which in 

fact is our methodology, albeit a conservative one), and without 

considering possible subsidies. Id. The LCOE and capital cost 

estimates above are direct cost comparisons, again consistent 

with the commenter’s position. 
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capacity that would otherwise be constructed. More important, 

Alstom does not challenge the specific cost estimates used by 

the EPA at proposal, nor disavow its own estimates of CCS costs 

(which are even less) which it is publically disseminating in 

the marketplace. See also Section V.F. 3 above, quoting Alstom’s 

press release stating unequivocally that “CCS works and is costeffective”. The EPA reasonably is relying on the specific Alstom 

estimates which it is using for its own commercial purposes, and 

not on the generalized concerns presented in its public 

comments. 

d. Use of cost information from EIA Annual Energy Outlook (AEO)

For the January 2014 proposal the EPA chose to rely on the 

EIA AEO 2013 cost projections for non-fossil based generation. 

The AEO presents long-term annual projections of energy supply, 

demand, and prices focused on U.S. energy markets. The 

predictions are based on results from EIA’s National Energy 

Modeling System (NEMS). The AEO costs are updated annually, they 

are highly scrutinized, and they are widely used by those 

involved in the energy sector. 

In the January 2014 proposal, the EPA presented LCOE costs 

for new non-fossil dispatchable generation (see 77 FR 1477, 

Table 7) from the AEO 2013. Those costs were updated as part of 

the AEO 2015 release. The estimated cost for all of these 

technologies decreased from AEO 2013 to AEO 2014 and AEO 2015. 
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This was due to changes in the interest rates that resulted in 

lower financing costs relative to those used the AEO 2013.

342 The 

EIA commissioned a comprehensive update of its capital cost 

assumptions for all generation technologies in 2013. Fuel cost 

and financial assumptions are updated for each edition of the 

Annual Energy Outlook.

e. Accounting for uncertainty of projected costs

As previously mentioned, the projected costs are dependent 

upon a range of assumptions including the projected capital 

costs, the cost of financing the project, the fixed and variable 

O&M costs, the projected fuel costs, and incorporation of any 

incentives such as tax credits or favorable financing that may 

be available to the project developer. There are also regional 

or geographic differences that affect the final cost of a 

project. The LCOE projections in this final action are not 

intended to provide an absolute cost for a new project using any 

of these respective technologies. Large construction projects –

as these would be – would be subjected to detailed cost analyses 

that would take into consideration site-specific information and 

specific design details in order to determine the project costs. 

The DOE/NETL noted that the cost estimates from their 

studies carry an accuracy in the range of -15 percent to +30 

 

342 www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf.
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percent, which is consistent with a “feasibility study” level of 

design. They also noted that the value of the studies lies “not 

in the absolute accuracy of the individual case results but in 

the fact that all cases were evaluated under the same set of 

technical and economic assumptions. This consistency of approach 

allows meaningful comparisons among the cases evaluated.”

The EIA AEO 2015 presented LCOE costs as a single point 

estimate representing average nationwide costs and separately as 

a range to represent the regional variation in costs. In order 

to compare the fossil fuel generation technologies from the NETL 

studies with the cost projections for non-fossil dispatchable 

technologies from EIA AEO 2015, we assume that the EIA studies 

would carry a similar level of uncertainty (i.e., +30 percent) 

and we present the AEO 2015 projected costs as the average 

nationwide LCOE with a range of -10 percent to +30 percent to 

account for uncertainty.343 The EIA does not provide uncertainty 

estimates in the AEO cost projections. However, nuclear experts

from EIA staff have indicated to the EPA that a range of 

uncertainty of -10 percent to +30 percent on the capital 

component of the LCOE can be expected based on market 

 

343 EIA does not provided uncertainty estimates in the AEO cost 

projections. However, EIA staff have indicated to the EPA that a 

range of uncertainty of -10%/+30% on the capital component of 

the LCOE can be expected based on market uncertainties. See 

memorandum “Range of uncertainty for AEO nuclear costs” 

available in the rulemaking docket, EPA-HQ-OAR-2013-0495.
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uncertainties. Specifically, these staff experts expect that 

nuclear plants currently under construction would not have 

capital costs under estimates and that one could expect to see a 

30 percent “upside” variation in capital cost. There is also 

insufficient market data to get a good statistical range of 

potential capital cost variation (i.e., only two plants under 

construction, neither complete). This is reasonably consistent 

with estimates for nuclear costs estimated by Lazard (see Table 

8 above) which likewise reflect a similar level of cost 

uncertainty. The Lazard nuclear costs show a range of projected 

levelized capital cost from $73/MWh to $110/MWh – a range of 50 

percent, very similar to the 40 percent range (i.e, -10 percent 

to +30 percent) suggested by EIA nuclear experts. The Global CCS 

Institute, in its most recent cost update, also provides nuclear 

costs as a range from $86/MWh to $102/MWh.344

3. Use of Costs from Current Projects

Although we are relying on cost estimates drawn from 

techno-economic models, we recognize that there are a few steam 

electric plants that include CCS that have been built, or are 

being constructed. Some information about the costs (or cost-to-

 

344 “The Costs of CCS and other Low-Carbon Technologies - 2015 

update” July 2015, Global CCS Institute, Available at: 

http://hub.globalccsinstitute.com/sites/default/files/publicatio

ns/195008/costs-ccs-other-low-carbon-technologies-2015-

update.pdf.
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date) for these projects is known. We discuss in this section 

the costs at facilities which have installed or are installing 

CCS, why the EPA does not consider those costs to be reasonably 

predictive of the costs of the next new plants to be built, and 

why the EPA considers that the next new plants will have lower 

costs along the lines predicted by NETL.345

The Boundary Dam Unit #3 facility utilizing post-combustion 

capture from Shell Cansolv is now operational. Petra Nova, a 

joint venture between NRG Energy Inc. and JX Nippon Oil & Gas 

Exploration, is currently constructing a post-combustion capture 

system at NRG’s WA Parish generating station near Houston, TX. 

The post-combustion capture system will utilize MHI amine-based 

 

345 The EPA notes that two of these facilities, Kemper and TCEP, 

received both assistance from DOE under EPAct05 and the IRC 

section 48A tax credit; and that the AEP Mountaineer pilot 

project received assistance from DOE under EPAct05. Under the 

most extreme interpretations of those provisions offered by 

commenters, the EPA would be precluded from any consideration of 

any information from those sources, including cost information,

in showing whether a system of emission reduction is adequately 

demonstrated. We note, however, that many of these same 

commenters urged consideration of the cost information from 

these sources. In fact, the EPA is not relying on information 

about the costs of these sources to determine the BSER or the 

standards of performance in this rulemaking, and the EPA is 

discussing the cost information here to explain why not. 

Accordingly, this discussion of cost information from these 

sources is not precluded by the EPAct05 and IRC section 48A 

provisions and, even if it is precluded, that would have no 

impact on the EPA’s determination of the BSER and the standards 

of performance in this rule. 
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solvents and is currently being constructed with plans to 

initiate operation in 2016.346

Construction on Mississippi Power’s Kemper County Energy 

Center IGCC facility is now nearly complete. The combined cycle 

portion of the facility has been generating power using natural 

gas. The gasification portion of the facility and the carbon 

capture system are undergoing system checks and training to 

enable commercial operations using a UOP SelexolTM pre-combustion 

capture system in early 2016.347

Another full-scale project, the Summit Power Texas Clean 

Energy Project has not commenced construction but remains a

viable project. Several other full-scale projects have been 

proposed and have progressed through the early stages of design, 

but have been cancelled or postponed for a variety of reasons.

Some cost information is also available for small 

demonstration projects – including those that have been 

supported by USDOE research programs. These projects would 

include Alabama Power’s demonstration project at Plant Barry and 

the AEP/Alstom demonstration at Plant Mountaineer. 

 

346 http://www.nrg.com/sustainability/strategy/enhancegeneration/carbon-capture/wa-parish-ccs-project/.

347 http://www.mississippipower.com/about-energy/plants/kempercounty-energy-facility/facts.
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Many commenters felt that the EPA should rely on those high 

costs when considering whether the costs are reasonable. The 

costs from these large-scale projects appear to be consistently 

higher than those projected by techno-economic models. However, 

the costs from these full-scale projects represent first-of-akind (FOAK) costs and, it is reasonable to expect these costs to 

come down to the level projected in the NETL and other technoeconomic studies for the next new projects that are built –

which are the sources that would be subject to this standard.

Significant reductions in the cost of CO2 capture would be 

consistent with overall experience with the cost of pollution 

control technology. A significant body of literature suggests 

that the per-unit cost of producing or using a given technology 

declines as experience with that technology increases over time, 

and this has certainly been the case with air pollution control 

technologies. Reductions in the cost of air pollution control 

technologies as a result of learning-by-doing, research and 

development investments, and other factors have been observed 

over the decades. We expect that the costs of capture technology 

will follow this pattern.

The NETL cost estimates reasonably account for this 

documented phenomenon. Specifically, “[I]n all cases, the report

intends to represent the next commercial offering, and relies on 

vendor cost estimates for component technologies. It also 
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applies process contingencies at the appropriate subsystem 

levels in an attempt to account for expected but undefined costs 

(a challenge for emerging technologies).”350

Commenters argued that the next plants to be built would 

still reflect first-of-a-kind costs, pointing to the newness of 

the technology and the lack of operating experience, i.e. the 

alleged absence of learning by doing. The EPA disagrees. In 

addition to operating experience from operating and partially 

constructed CCS projects, substantial research efforts are 

underway providing a further knowledge base to reduce CO2 capture 

costs and to improve performance.

The DOE/NETL sponsors an extensive research, development 

and demonstration program that is focused on developing advanced 

technology options that will dramatically lower the cost of 

capturing CO2 from fossil fuel energy plants compared to 

currently available capture technologies. The large-scale CO2

capture demonstrations that are currently planned and in some 

cases underway, under DOE’s initiatives, as well as other 

domestic and international projects, will generate operational 

knowledge and enable continued commercialization and deployment 

of these technologies. Gas absorption processes using chemical 

 

350 “Cost and Performance Baseline for Fossil Energy Plants 

Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity

Revision 3”, DOE/NETL-2015/1723 (July 2015) at p. 38.
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solvents, such as amines, to separate CO2 from other gases have 

been in use since the 1930s in the natural gas industry and to 

produce food and chemical grade CO2. The advancement of aminebased solvents is an example of technology development that has 

improved the cost and performance of CO2 capture. Most single 

component amine systems are not practical in a flue gas 

environment as the amine will rapidly degrade in the presence of 

oxygen and other contaminants. The Fluor Econamine FG process, 

the process modeled in the NETL cost study for the SCPC cases, 

uses a monoethanolamine (MEA) formulation specially designed to

recover CO2 and contains a corrosion inhibitor that allows the 

use of less expensive, conventional materials of construction. 

Other commercially available processes use sterically hindered 

amine formulations (for example, the Mitsubishi Heavy Industries 

KS–1 solvent) which are less susceptible to degradation and 

corrosion issues. 

The DOE/NETL and private industry are continuing to sponsor 

research on advanced solvents (including new classes of amines) 

to improve the CO2 capture performance and reduce costs.

As noted in Section V.H.7.d above, SaskPower has created 

the CCS Global Consortium to facilitate further knowledge 

regarding, and use of, carbon capture technology.

351 This 

 

351 http://www.saskpowerccs.com/consortium/.
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consortium provides SaskPower the opportunity to share its 

knowledge and experience with global energy leaders, technology 

developers, and project developers. SaskPower, in partnership 

with Mitsubishi and Hitachi, is also helping to advance CCS 

knowledge and technology through the creation of the Shand 

Carbon Capture Test Facility (CCTF).352 The test facility will 

provide technology developers with an opportunity to test new 

and emerging carbon capture systems for controlling carbon 

emissions from coal-fired power plants. 

We also note certain features of the commercial plants 

already built that suggest that their costs are uniquely high, 

and otherwise not fairly comparable to the costs of plants 

meeting the NSPS using the BSER. Most obviously, many of these 

projects involve deeper capture than the partial CCS that the 

EPA assumes in this final action. In addition, cost overruns at 

the Kemper facility, mentioned repeatedly in the public 

comments, resulted in major part from highly idiosyncratic 

circumstances, and are related to the cost of the IGCC system, 

not to the cost of CCS.353 The EPA does not believe that these 

 

352 http://www.saskpowerccs.com/ccs-projects/shand-carboncapture-test-facility/.

353 See Independent Monitor’s Prudency Evaluation Report for the 

Kemper County IGCC Project (prepared for Mississippi Public 

Utilities Staff), available at 

www.psc.state.ms.us/InsiteConnect/InSiteView.aspx?model=INSITE_C

ONNECT&queue=CTS_ARCHIVEQ&docid=328417 (“Report”). As documented 
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unusual circumstances are a reasonable basis for assessing costs 

of either CCS or IGCC here.

4. Cost Competitiveness of New Coal Units

As the EPA noted, all indications suggest that very few new 

coal-fired power plants will be constructed in the foreseeable 

future. Although a small number of new coal-fired power plants 

have been built recently, the industry generally is not building 

these kinds of power plants at present and is not expected to do 

so for the foreseeable future. The reasons include the current 

economic environment and improved energy efficiency, which has 

led to lower electricity demand, and competitive current and 

projected natural gas prices. On average, the cost of generation 

from a new NGCC power plant is expected to be lower than the 

cost of generation from a new coal-fired power plant, and the 

 

in this Report, costs escalated significantly because the 

developers adopted a “compressed schedule” in an attempt to 

obtain the IRC 48A tax credit, resulting in “engineering and 

design changes which are a normal result of detailed engineering 

and design ... occurring at the same time as, rather than ahead 

of, construction activities”, which did not allow for proper 

sequencing during construction. This “’just-in-time’ approach to 

engineering and procurement (meaning that the engineering was 

often completed shortly before material procurement and 

construction activities) resulted in a greater number of 

construction work-arounds, congestion of construction craft 

labor in the field, inefficiencies and additional steps that 

became necessary during construction to cope with this just-intime engineering, procurement and construction approach.” 

Report, p. 6. Ironically, work was still completed too late to 

obtain the tax credit. Id. p. 15. 
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EPA has concluded that, even in the absence of the requirements 

of this final rule, very few new coal-fired power plants will be 

built in the near term.

Some commenters, however, disagreed with this conclusion.

They contended instead that it is the CCS-based NSPS that would 

preclude such new generation. However, as the EPA has discussed, 

there is considerable evidence that utilities and project 

developers are moving away – or have already moved away – from a 

long term dependence on coal-fired generating sources. A review 

of publicly available integrated resource plans show that many 

utilities are not considering construction of new coal-fired 

sources without CCS. See Section V. H.3 above. Few new coalfired generating sources have commenced construction in the past 

5 years and, of the projects that are currently in the 

development phase, the EPA is only aware of projects that will 

include CCS in the design. As we have noted in this preamble, 

the bulk of new generation that has been added recently has been

either natural gas-fired or renewable sources. Overall, the EPA 

remains convinced that the energy sector modeling is reflecting 

the realities of the market in predicting very few new coalfired power plants in the near future – even in the absence of 

these final standards.

In addition, we note that the Administration’s CCS Task 

Force report recognized that CCS would not become more widely 
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available without the advent of a regulatory framework that 

promoted CCS or provided a strong price signal for CO2. In this 

regard, we note American Electric Power’s statements regarding 

the need for federal requirement for GHG control to aid in cost 

recovery for CCS projects, to attract other investment partners, 

and thereby promote advancement and deployment of CCS 

technology: “as a regulated utility, it is impossible to gain 

regulatory approval to recover our share of the costs for 

validating and deploying the technology without federal 

requirements to reduce greenhouse gas emissions already in 

place. The uncertainty also makes it difficult to attract 

partners to help fund the industry’s share”.354 Indeed, AEP has 

stated that CCS is important for the very future of the 

industry: “AEP still believes the advancement of CCS is critical 

for the sustainability of coal-fired generation.”355 This final 

rule’s action is an important component in developing that 

needed regulatory framework.

 

354 www/aep.com/newsroom/newsreleases/?id=1704.

355 “CCS LESSONS LEARNED REPORT American Electric Power 

Mountaineer CCS II Project Phase 1”, prepared for The Global CCS 

Institute Project # PRO 004, January 23, 2012, page 2. Available 

at: www.globalccsinstitute.com/publications/ccs-lessons-learnedreport-american-electric-power-mountaineer-ccs-ii-project-phase1; See also AEP FEED Study at pp. 4, 63, Available at: 

www.globalccsinstitute.com/publications/aep-mountaineer-iiproject-front-end-engineering-and-design-feed-report.
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5. Accuracy of Cost Estimates for Transportation and Geologic 

Sequestration

The EPA’s estimates of costs take into account the 

transport of CO2 and sequestration of captured CO2. Estimates of 

transport and sequestration costs – approximately $5-$15 per ton 

of CO2 - are based on DOE NETL studies and are also consistent 

with other published studies.

356 For transport, costs reflect

pipeline capital costs, related capital expenditures, and O&M 

costs. Sequestration cost estimates reflect the cost of site 

screening and evaluation, the cost of injection wells, the cost 

of injection equipment, operation and maintenance costs, pore 

volume acquisition expense, and long term liability protection. 

These sequestration costs reflect the regulatory requirements of 

the Underground Injection Control Class VI program and GHGRP

subpart RR for geologic sequestration of CO2 in deep saline 

 

356 Updated Costs (June 2011 Basis) for Selected Bituminous 

Baseline Cases (DOE/NETL-341/082312); Cost and Performance of PC 

and IGCC Plants for a Range of Carbon Dioxide Capture (DOE/NETL2011/1498); Cost and Performance Baseline for Fossil Energy 

Plants (DOE/NETL-2010/1397); Economic Evaluation of CO2 Storage 

and Sink Enhancement Options, Tennessee Valley Authority, NETL 

and EPRI, December 2002; Carbon Dioxide and Transport and 

Storage Costs in NETL Studies (DOE/NETL-2013/1614), March 2013; 

Carbon Dioxide and Transport and Storage Costs in NETL Studies

(DOE/NETL-2014/1653), May 2014; Cost and Performance Baseline 

for Fossil Energy Power Plants, Volume 1a: Bituminous Coal (PC) 

and Natural Gas to Electricity (DOE-NETL-2015/1723), July 2015.
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formations, which are discussed further in Sections V. M. and N

below.

357

Based on DOE/NETL studies, the EPA estimated that the total 

CO2 transportation, storage, and monitoring (TSM) cost associated 

with EGU CCS would comprise less than 5.5 percent of the total 

cost of electricity in all capture cases modeled - approximately 

$5-$15 per ton of CO2.

358 The range of TSM costs the EPA relied on 

are broadly consistent with estimates provided by the Global 

Carbon Capture and Storage Institute as well.

359 Some commenters 

suggested that the EPA underestimated the costs associated with 

transporting captured CO2 from an EGU to a sequestration site.360

Specifically, commenters suggested that the EPA’s estimated 

costs for constructing pipelines were lower than costs based on 

actual industry experience. Commenters also opined that the 

EPA’s assumed length of pipeline needed between the EGU and the 

sequestration site is not reasonable and that the DOE/NETL study 

upon which the EPA relied does not account for CO2 transport 

costs when EOR is not available. 

 

357 Carbon Dioxide and Transport and Storage Costs in NETL 

Studies. DOE/NETL-2013/1614. March 2013. P. 13.

358 RIA at section 5.5; proposed rule RIA at 5-30.

359

http://hub.globalccsinstitute.com/sites/default/files/publicatio

ns/12786/economic-assessment-carbon-capture-and-storagetechnologies-2011-update.pdf.

360 See, for example, comments from American Electric, pp 97-8, 

Southern Company, pp. 47-48, and Duke Power p. 98.
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The EPA believes its estimates of transportation and 

sequestration costs are reasonable. First, the EPA in fact 

includes cost estimates for CO2 transport when EOR opportunities 

are not available – consistent with its overall conservative 

cost methodology of assuming no revenues from sale of captured 

CO2. Specifically, the EPA estimates transport, storage and 

monitoring (TSM) costs of $5-$15 per ton of CO2 for non-EOR 

applications.361 This estimate is reflected in the LCOE 

comparative costs.362

The EPA also carefully reviewed the assumptions on which 

the transport cost estimates are based and continues to find 

them reasonable. The NETL studies referenced in Section V.I.2 

above based transport costs on a generic 100 km (62 mi) pipeline

and a generic 80 kilometer pipeline.

363 At least one study

estimated that of the 500 largest point sources of CO2 in the 

United States, 95 percent are within 50 miles of a potential 

storage reservoir.364 As a point of reference, the longest CO2

 

361 See RIA at section 5.5 and proposed RIA at 5-30.

362 See RIA at section 5.5.

363 The pipeline diameter was sized for this to be achieved 

without the need for recompression stages along the pipeline 

length. 

364 JJ Dooley, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH 

Kim, EL Malone (2006), Carbon Dioxide Capture and Geologic 

Storage: A Key Component of a Global Energy Technology Strategy 

to Address Climate Change. Joint Global Change Research 

Institute, Battelle Pacific Northwest Division. PNWD-3602. 

College Park, MD.
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pipeline in the United States is 502 miles.365 For new sources, 

pipeline distance and costs can be factored into siting and, as

discussed in Section V.M, there is widespread availability of 

geologic formations for geologic sequestration (GS). Moreover, 

data from the Pipeline and Hazardous Materials Safety 

Administration show that in 2013 there were 5,195 miles of CO2

pipelines operating in the United States. This represents a 

seven percent increase in CO2 pipeline miles over the previous 

year and a 38 percent increase in CO2 pipeline miles since 2004. 

For the reasons outlined above, the EPA believes its estimates 

have a reasoned basis. See also Section V.M below further 

discussing the current availability of CO2 pipelines.

With respect to sequestration, certain commenters argued 

that the EPA’s cost analysis failed to account for many 

contingencies and uncertainties (surface and sub-surface 

property rights in particular), ignored the costs of GHGRP

subpart RR, and also was not representative of the costs 

associated with specific GS site characterization, development, 

and operation/injection of monitoring wells. Commenter American 

Electric Power (AEP) referred to its own experience with the 

Mountaineer demonstration project. AEP noted that although this 

 

365 A Review of the CO2 Pipeline Infrastructure in the U.S., April 

21, 2015, DOE/NETL-2014/1681, Office of Fossil Energy, National 

Energy Technology Laboratory. 
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project was not full scale, finding a suitable repository, 

notwithstanding a generally favorable geologic area, proved 

difficult. The company referred to its estimated cost of 

expanding the existing Mountaineer plant to a larger scale 

project, particularly the cost of site characterization and well

construction.

366

The EPA’s cost estimates account for the requirements of 

the Underground Injection Control Class VI program, and GHGRP

subpart RR, among them site screening and evaluation costs, 

costs for injection wells and equipment, O&M costs, and 

monitoring costs. The estimated sequestration costs include 

operational and post-injection site care monitoring, which are 

components of the UIC Class VI requirements, and also reflect 

costs for sub-surface pore volume property rights acquisition.

367

These estimates are consistent with the costs presented in the 

study CO2 Storage and Sink Enhancements: Developing Comparable 

Economics, which incorporates the costs associated with site 

evaluation, well drilling, and the capital equipment required 

 

366 AEP Comments at pp. 93, 96. 

367 “Cost and Performance of PC and IGCC Plants for a Range of 

Carbon Dioxide Capture.” DOE/NETL-2011/1498 (September 2013) p.

49. Specifically, the report estimates the costs associated with 

acquiring rights to use the pore space in the geologic 

formation. Costs are estimated based on studies of subsurface 

rights acquisition for natural gas storage. The report also 

estimates costs for land acquisition for surface property 

rights. Id. p. 48.
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for transporting and injecting CO2.

368,369 Monitoring costs were 

evaluated based on the methodology set forth in the 

International Energy Agency Greenhouse Gas R&D Programme’s 

Overview of Monitoring Projects for Geologic Storage Projects

report.370

The EPA’s cost estimates for sequestration thus cover all

aspects commenters claimed the EPA disregarded. The EPA believes 

that the use of costs and scenarios presented in the studies 

referenced are representative for purposes of the cost analysis. 

The NETL cost estimates upon which the EPA’s costs draw directly 

from the UIC Class VI economic impact analysis.371 That analysis 

is based on estimated characteristics for a representative group 

of projects over a 50-year period of analysis, as well as 

industry averages for several cost components and sub-

 

368 Bock, B., R. Rhudy, H. Herzog, M. Klett, J. Davidson, D G. De 

La Torre Ugarte, and D. Simbeck. (2003). Economic Evaluation of 

CO2 Storage and Sink Enhancement Options, Final Technical Report 

Prepared by Tennessee Valley Authority for DOE.

369 As noted above, other sequestration-related costs are also 

estimated, including injection wells and equipment, pore volume 

acquisition, and long-term-liability. “Cost and Performance

Baseline for Fossil Energy Plants Volume 1: Bituminous Coal

and Natural Gas to Electricity Revision 2a, September 2013

DOE/NETL-2010/1397, p. 55.

370 “Overview of Monitoring Requirements for Geologic Storage 

Projects”, IEA Greenhouse Gas R&D Programme, Report Number 

PH4/29, November 2004.

371 Cost Analysis for the Federal Requirements Under the 

Underground Injection Control Program for Carbon

Dioxide Geologic Sequestration Wells, U.S. Environmental 

Protection Agency Office of Water, EPA 816-R10-013, November 

2010, pages 3-1, 5-42.
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components. The EPA also made reasonable assumptions regarding 

the assumed injection site: a deep saline formation with typical 

characteristics (e.g., representative depth and pressure).373

With respect to AEP’s experience with the Mountaineer 

demonstration project, sequestration siting issues are of course 

site-specific, and raise individual issues. For this reason, it 

is inappropriate to generalize from a particular individual 

experience. In this regard, as explained in Section V.N below, 

the construction permits issued by the EPA to-date under the 

Underground Injection Control Class VI regulations required far 

fewer wells for site characterization and monitoring than AEP 

found to be necessary at its Mountaineer site. Moreover, 

notwithstanding difficulties, the company was able to 

successfully drill and complete wells, and safely inject 

captured CO2. The company also indicated it fully expected to be 

able to do so at full scale and explained how.374 For discussion 

of 40 CFR part 98 subpart RR (the GHGRP requirements for 

 

373 Economic Evaluation of CO2 Storage and Sink Enhancement 

Options, Tennessee Valley Authority, NETL and EPRI, December 

2002.

374 See “CCS front end engineering & design report: American 

Electric Power Mountaineer CCS II Project. Phase 1” at pp. 36-

43. The company likewise explained the monitoring regime it 

would utilize to verify containment, and the well construction 

it would utilize to guarantee secure sequestration. Id. at pp. 

44-54. Available at: 

http://www.globalccsinstitute.com/publications/aep-mountaineerii-project-front-end-engineering-and-design-feed-report.
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geologic sequestration), including costs associated with 

compliance with those requirements, see Section V.N below.

J. Achievability of the Final Standards

The EPA finds the final standard of 1,400 lb CO2/MWh-g to be 

achievable over a wide range of variable conditions that are 

reasonably likely to occur when the system is properly designed 

and operated. As discussed elsewhere, the final standard 

reflects the degree of emission limitation achievable through 

the application of the BSER which we have determined to be a 

highly efficient SCPC implementing partial CCS at a level 

sufficient to achieve the final standard – for such a unit 

utilizing bituminous coal that would be approximately 16 

percent. In determining the predicted cost and performance of 

such a system, the EPA utilized information contained in updated 

DOE/NETL studies that assumed use of bituminous coal and an 85 

percent capacity factor. Here we examine the effects of 

deviating from those assumed operational parameters on the 

achievability of the final standard of performance.375 This is in 

keeping with the requirement that a standard of performance must 

be achievable accounting for all normal operating variability 

 

375 Additional information can be found in a Technical Support 

Document (TSD) – “Achievability of the Standard for Newly 

Constructed Steam Generating EGUs” available in the rulemaking 

docket.
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when a control system is properly designed, maintained, and 

operated. See Section III.H.1.c above.

1. Operational Fluctuations, Start-ups, Shutdowns, and 

Malfunctions

Importantly, compliance with the standard must be 

demonstrated over a 12-operating-month average. The total CO2

emissions (pounds of CO2) over 12 operational months are summed 

and divided by the total gross output (in megawatt-hours) over 

the same 12 operational months. Such a compliance averaging 

period is very forgiving of short-term excursions that can be 

associated with non-routine events such as start-ups, shutdowns, 

and malfunctions. A new fossil fuel-fired steam generating EGU –

if constructed – would, most likely, be built to serve base load 

power demand and would not be expected to routinely start-up or 

shutdown or ramp its capacity factor in order to follow load 

demand. Thus, planned start-up and shutdown events would only be 

expected to occur a few times during the course of a 12-

operating-month compliance period. Malfunctions are unplanned 

and unpredictable events and emission excursions can happen at 

or around the time of the equipment malfunction. But a 

malfunctioning EGU that cannot be operated properly should be 

shut down until the malfunctioning equipment can be addressed 

and the EGU can be restarted to operate properly. 
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The post-combustion capture systems that have been utilized 

have proven to be reliable. The Boundary Dam facility has been 

operating full CCS successfully at commercial scale since 

October 2014. As described earlier, in evaluating results from

the Mountaineer slip-stream demonstration, AEP and Alstom 

reported robust steady-state operation during all modes of power 

plant operation including load changes, and saw an availability 

of the CCS system of greater than 90 percent.376

2. Variations in Coal Type

The use of specific coal types can affect the amount of CO2

that is emitted from a new coal-fired power plant. As previously 

discussed, the EPA utilized studies by the DOE/NETL to predict 

the cost and performance of new steam generating units. Based on 

those reports, the EPA predicts that a new SCPC burning low rank 

coal (subbituminous coal or dried lignite) would have an 

uncontrolled emission rate about 7 percent higher than a similar 

 

376 http://www.alstom.com/press-centre/2011/5/alstom-announcessucessful-results-of-mountaineer-carbon-capture-andsequestration-ccs-project/. The Boundary Dam facility likewise 

is operating reliably (see Section V.D.3.a above). See also 

“Cost and Performance Baseline for Fossil Energy Plants Volume 

1a: Bituminous Coal (PC) and Natural Gas to Electricity, 

Revision 3”, DOE/NETL-2015/1723 (July 2015) at p. 36 (“[t]he 

capture and CO2 compression technologies have commercial 

operating experience with demonstrated ability for high 

reliability”).
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unit firing typical bituminous coal.377 The EPA predicts that 

such a highly efficient new SCPC utilizing subbituminous coal or 

dried lignite would need to capture approximately 23 percent of 

the CO2. The EPA also believes that it is technically feasible to 

do so, although additional cost would be entailed. The EPA has 

evaluated those costs and finds them to remain reasonable.378 As 

shown in Table 8 above, the predicted cost remains within the 

estimated range for the other principal base load, dispatchable 

non-NGCC alternative technologies. Estimated capital cost using 

these coal types would also be somewhat higher, an estimated 23

percent increase.379 The EPA finds these increases to be 

reasonable because, as discussed earlier, the costs are 

reasonably consistent with capital cost increases in previous 

NSPS. See Section V.H.4 above. 

K. Emission Reductions Utilizing Partial CCS

Although the definition of “standard of performance” does 

not by its terms identify the amount of emissions from the 

 

377 For additional detail, see the Technical Support Document 

(TSD) – “Achievability of the Standard for Newly Constructed 

Steam Generating EGUs” – available in the rulemaking docket.

378 The cost of the lignite drying equipment is assumed to be low 

compared to the cost of the carbon capture equipment. Further, 

pre-drying of the lignite reduces fuel, auxiliary power 

consumption and other O&M costs. www.ieacoal.org.uk/documents/83436/9095/Techno-economics-of-modern-predrying-technologies-for-lignite-fired-power-plants,-CCC/241.

379 Note that the 23 percent increase in expected capital costs 

and the 23 percent CO2 capture needed to meet the final standard 

are coincidental and are not correlated.
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category of sources and the amount of emission reductions 

achieved as factors the EPA must consider in determining the 

“best system of emission reduction,” the D.C. Circuit has stated 

that the EPA must do so. See Sierra Club v. Costle, 657 F.2d at

326 (“we can think of no sensible interpretation of the 

statutory words “best ... system” which would not incorporate the 

amount of air pollution as a relevant factor to be weighed when 

determining the optimal standard for controlling ... 

emissions”).380 This is consistent with the Court’s statements in 

Essex Chemical Corp. v. Ruckelshaus, 486 F.2d at 437 that it is 

necessary to “[k]eep[] in mind Congress’ intent that new plants 

be controlled to the ‘maximum practicable degree’”.

The final standard of performance will result in meaningful 

and significant emission reductions of GHG emissions from a new 

coal-fired steam generating unit. The EPA estimates that a new 

highly efficient 500 MW coal-fired SCPC meeting the final 

standard of 1,400 lb CO2/MWh-g will emit about 354,000 fewer 

metric tons of CO2 each year than that new highly efficient unit 

would have emitted otherwise. That is equivalent to taking about 

 

380 Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was 

governed by the 1977 CAAA version of the definition of “standard 

of performance,” which revised the phrase ‘‘best system’’ to 

read, “best technological system.” The 1990 CAAA deleted 

“technological,” and thereby returned the phrase to how it read 

under the 1970 CAAA. The Sierra Club v. Costle’s interpretation 

of this phrase to require consideration of the amount of air 

emissions remains valid for the phrase “best system.”
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75,000 vehicles off the road each year381 and will result in over

14,000,000 fewer metric tons of CO2 in a 40-year operating life.

To emphasize the importance of constructing a highly efficient 

SCPC unit that includes partial CCS - the highly efficient 500 

MW coal-fired SCPC with partial CCS would emit about 675,000 

fewer metric tons of CO2 each year than that from a new, less 

efficient coal-fired utility boiler with an assumed emission of 

1,800 lb CO2/MWh-g.

For comparison, see Table 12 below which provides the 

amount of CO2 emissions captured each year by other CCS projects.

These result show that, even though the emission reductions are 

significant, they are reasonably within the range of emission 

reductions that are currently being achieved now in existing 

facilities. For comparison, approximately 60,000,000 metric tons 

of CO2 were supplied to U.S. EOR operations in 2013.382

Table 12. Annual Metric Tons of CO2 Captured (or predicted to 

capture) from CCS Projects and from a Model 500 MW Plant Meeting 

the Final Standard.

CO2 captured 

Project tonnes/year 

AES Shady Point 66,000 

AES Warrior Run 110,000 

Southern Company Plant Barry 165,000 

Searles Valley Minerals 270,000 

 

381 Using U.S. EPA Office of Transportation and Air Quality 

(OTAQ) estimate of average vehicle emissions of 4.7 tonnes/year. 

382 Greenhouse Gas Reporting Program, data reported as of August 

18, 2014.
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New 500 MW SCPC EGU (1,400 lb CO2/MWh-g) 354,000

Coffeyville Fertilizer 700,000 

Boundary Dam #3 1,000,000 

Petra Nova/NRG WA Parish 1,400,000 

Dakota Gasification 3,000,000 

L. Further Development and Deployment of CCS Technology

Researchers at Carnegie Mellon University (CMU) have 

studied the history and the technological response to 

environmental regulations.384 By examining U.S. research funding 

and patenting activity over the past century, the CMU 

researchers found that promulgation of national policy requiring

large reductions in power-plant emissions resulted in a 

significant upswing in inventive activity to develop 

technologies to reduce those emissions. The researchers found 

that, following the 1970 Clean Air Act, there was a 10-fold 

increase in patenting activity directed at improving the SO2

scrubbers that were needed to comply with stringent federal and 

state-level standards.

 

384 See Technical Support Document/Memorandum “History Of Flue 

Gas Desulfurization in the United States” (July 11, 2017) 

summarizing the doctoral dissertation of Margaret R. Taylor, 

“The Influence of Government Actions on Innovative Activities in 

the Development of Environmental Technologies to Control Sulfur 

Dioxide Emissions from Stationary Sources,” MA dissertation 

submitted to the Carnegie Institute of Technology, Carnegie 

Mellon University in partial fulfillment of the requirements for 

the degree of Doctor of Philosophy in Engineering and Public 

Policy, Pittsburgh, PA, January 2001.
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Much like carbon capture scrubbers today, the technology to 

capture and remove SO2 from power plant flue gases was new to the 

industry and was not yet widely deployed at large coal-burning 

plants when the EPA first promulgated the 1971 standards. 

Many of the early Flue Gas Desulfurization (FGD) units did 

not perform well, as the technology at that time was poorly 

understood and there was little or no prior experience on coalfired power plants. In contrast, amine-based capture systems 

have a much longer history of reliable use at coal-fired plants 

and other industrial sources. There is also a better

understanding of the amine process chemistry and overall process 

design – and project developers have much sophisticated 

analytical tools available today than in the 1970s during the 

development of FGD scrubber technologies. 

While R&D efforts were essential to achieving improvements

in FGD scrubber technology – and are also very important to 

improving carbon capture technologies, the influence of 

regulatory actions that establish commercial markets for 

advanced technologies cannot be minimized. The existence of 

national government regulation for SO2 emissions control 

stimulated innovation, as shown by the patent analysis following 

initial SO2 regulatory requirements for EGU emissions. The study 

author further found that regulatory stringency appears to be 

particularly important as a driver of innovation, both in terms 
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of inventive activity and in terms of the communication 

processes involved in knowledge transfer and diffusion. Further, 

as electric power generation doubled, the operating and 

maintenance costs of FGD systems decline to 83 percent of their 

original level. This finding, which is very much in line with 

progress ratios determined in other industries, shows that 

quantifiable technological improvements can be shown to occur 

solely on the basis of the experience of operating an 

environmental control technology forced into being by government 

actions.

M. Technical and Geographic Aspects of Disposition of Captured 

CO2

In the following sections of the preamble, we discuss 

issues associated with the disposition of captured CO2: the “S” -

sequestration – in CCS. In this section, we review the existing 

processes, technologies, and geologic conditions that enable 

successful geologic sequestration (GS). In Section V.N., we 

discuss in detail the comprehensive, in-place regulatory 

structure that is currently available to oversee GS projects and 

assure their safety and effectiveness. Together, these 

discussions demonstrate that the technical feasibility of GS, 

another key component of a partial CCS unit, is adequately 

demonstrated. Sequestration is already well proven. CO2 has been 

retained underground for eons in geologic (natural) repositories 
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and the mechanisms by which CO2 is trapped underground are well 

understood. The physical and chemical trapping mechanisms, along 

with the regulatory requirements and safeguards of the 

Underground Injection Control Program and complementary 

monitoring and reporting requirements of the GHGRP, together 

ensure that sequestered CO2 will remain secure and provide the 

monitoring to identify and address potential leakage using Safe 

Drinking Water Act (SDWA) and CAA authorities (see Section V.N

of this preamble).

386

1. Geologic and Geographic Considerations for GS

Geologic sequestration (i.e., long-term containment of a CO2

stream in subsurface geologic formations) is technically 

feasible and available throughout most of the United States. GS 

is based on a demonstrated understanding of the processes that 

affect CO2 fate in the subsurface; these processes can vary 

regionally as the subsurface geology changes. GS occurs through 

a combination of mechanisms including: 1) structural and 

 

386 See also Carbon Sequestration Council and Southern Company 

Services v. EPA, No. 14-1406 (D.C. Cir. June 2, 2015) at *10

(“[c]arbon capture and storage is an emerging climate change 

mitigation program that involves capturing carbon dioxide from 

industrial sources, compressing it into a ‘supercritical fluid,’ 

and injecting that fluid underground for the purposes of 

geologic sequestration, with the goal of preventing the carbon 

from reentering the atmosphere. Because the last of these steps 

– geologic sequestration of the supercritical carbon dioxide –

involves that injection of fluid into underground wells, it is 

subject to regulation under the Safe Drinking Water Act”).
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stratigraphic trapping (generally trapping below a low 

permeability confining layer); 2) residual CO2 trapping 

(retention as an immobile phase trapped in the pore spaces of 

the geologic formation); 3) solubility trapping (dissolution in 

the in situ formation fluids); 4) mineral trapping (reaction 

with the minerals in the geologic formation and confining layer 

to produce carbonate minerals); and 5) preferential adsorption 

trapping (adsorption onto organic matter in coal and shale).387

These mechanisms are functions of the physical and chemical 

properties of CO2 and the geologic formations into which the CO2

stream is injected. Subsurface formations suitable for GS of CO2

captured from affected EGUs are geographically widespread 

throughout most parts of the United States.

Storage security is expected to increase over time through 

post-closure, resulting in a decrease in potential risks.388 This 

expectation is based in part on a technical understanding of the 

variety of trapping mechanisms that work to reduce CO2 mobility 

over time.389 In addition, site characterization, site 

operations, and monitoring strategies can work in combination to 

promote storage security.

 

387 See, e.g., USEPA. 2008. Vulnerability Evaluation Framework 

for Geologic Sequestration of Carbon Dioxide.

388 Report of the Interagency Task Force on Carbon Capture and 

Storage (August 2010), page 47.

389 See, e.g., Intergovernmental Panel on Climate Change. (2005). 

Special Report on Carbon Dioxide Capture and Storage.
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The effectiveness of long-term trapping of CO2 has been 

demonstrated by natural analogs in a range of geologic settings 

where CO2 has remained trapped for millions of years.390 For 

example, CO2 has been trapped for more than 65 million years in 

the Jackson Dome, located near Jackson, Mississippi.391 Other 

examples of natural CO2 sources include Bravo Dome and McElmo 

Dome in Colorado and New Mexico, respectively. These natural 

storage sites are themselves capable of holding volumes of CO2

that are larger than the volume of CO2 expected to be captured 

from a fossil fuel-fired EGU. In 2010, the Department of Energy 

(DOE) estimated current CO2 reserves of 594 million metric tons 

at Jackson Dome, 424 million metric tons at Bravo Dome, and 530 

million metric tons at McElmo Dome.392

GS is feasible in different types of geologic formations 

including deep saline formations (formations with high salinity 

formation fluids) or in oil and gas formations, such as where 

injected CO2 increases oil production efficiency through a 

process referred to as enhanced oil recovery (EOR). Both deep 

 

390 Holloway, S., J. Pearce, V. Hards, T. Ohsumi, and J. Gale. 

2007. Natural Emissions of CO2 from the Geosphere and their 

Bearing on the Geological Storage of Carbon Dioxide. Energy 32: 

1194–1201.

391 Intergovernmental Panel on Climate Change. (2005). Special 

Report on Carbon Dioxide Capture and Storage.

392 DiPietro, P., Balash, P. & M. Wallace. A Note on Sources of 

CO2 Supply for Enhanced-Oil Recovery Operations. SPE Economics & 

Management. April 2012.
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saline and oil and gas formation types are widely available in 

the United States. The geographic availability of deep saline 

formations and EOR is shown in Figure 1 below.

393 As shown in the 

figure, there are 39 states for which onshore and offshore deep 

saline formation storage capacity has been identified.394 EOR 

operations are currently being conducted in 12 states. An 

additional 17 states have geology that is amenable to EOR 

operations. Figure 1 also shows areas that are within 100 

kilometers (62 miles) of where storage capacity has been 

identified.395 There are 10 states with operating CO2 pipelines 

and 18 states that are within 100 kilometers (62 miles) of an 

active EOR location.

CO2 may also be used for other types of enhanced recovery, 

such as for natural gas production. Reservoirs such as 

unmineable coal seams also offer the potential for geologic 

storage.396 Enhanced coalbed methane recovery is the process of 

injecting and storing CO2 in unmineable coal seams to enhance 

 

393 A color version of the figure, which readers may find easier 

to view, can be found in the technical support document on 

geographic availability in the rulemaking docket.

394 Alaska is not shown in Figure 1; it has deep saline formation 

storage capacity, geology amenable to EOR operations, and 

potential GS capacity in unmineable coal seams.

395 The distance of 100 kilometers reflects assumptions in DOENETL cost estimates which the EPA used for cost estimation 

purposes. See “Carbon Dioxide and Transport and Storage Costs in 

NETL Studies”, DOE/NETL-2014/1653 (May 2014).

396 Other types of opportunities include organic shales and 

basalt.
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methane recovery. These operations take advantage of the 

preferential chemical affinity of coal for CO2 relative to the 

methane that is naturally found on the surfaces of coal. When CO2

is injected, it is adsorbed to the coal surface and releases 

methane that can then be captured and produced. This process 

effectively “locks” the CO2 to the coal, where it remains stored. 

DOE has identified over 54 billion metric tons of potential CO2

storage capacity in unmineable coal across 21 states.397 The 

availability of unmineable coal seams is shown in Figure 1

below.

As discussed below in Section M.7, a few states do not have 

geologic conditions suitable for GS, or may not be located in 

proximity to these areas. However, in some cases, demand in 

those states can be served by coal-fired power plants located in 

areas suitable for GS, and in other cases, coal-fired power 

plants are unlikely to be built in those areas for other 

reasons, such as the lack of available coal or state law 

prohibitions and restrictions against coal-fired power plants.398

 

397 The United States 2012 Carbon Utilization and Storage Atlas, 

Fourth Edition, U.S. Department of Energy, Office of Fossil 

Energy, National Energy Technology Laboratory (NETL).

398 Similarly, as discussed below, the U.S. territories lack 

available coal, do not currently have coal-fired power plants, 

and, as a result, are not expected to see new coal-fired power 

plants. Hawaii is not expected to constructed new coal plants as 

it intends to utilize 100 percent renewable energy sources by 

2050.
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Figure 1: Geologic Sequestration in the Continental United 

States
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Figure 2 – Electrical Transmission Lines across the 

Continental United States399

2. Availability of Geologic Sequestration in Deep Saline 

Formations

The DOE and the United States Geological Survey (USGS) have 

independently conducted preliminary analyses of the availability 

and potential CO2 sequestration capacity of deep saline 

formations in the United States. DOE estimates are compiled by 

the DOE’s National Carbon Sequestration Database and Geographic 

Information System (NATCARB) using volumetric models and 

published in a Carbon Utilization and Storage Atlas.400 DOE 

estimates that areas of the United States with appropriate 

geology have a sequestration potential of at least 2,035 billion 

metric tons of CO2 in deep saline formations. According to DOE 

and as noted above, at least 39 states have geologic 

characteristics that are amenable to deep saline GS in either 

onshore or offshore locations. In 2013, the USGS completed its 

evaluation of the technically accessible GS resources for CO2 in 

U.S. onshore areas and state waters using probabilistic 

 

399 Ventyx Velocity Suite Online. April 2015.

400 The United States 2012 Carbon Utilization and Storage Atlas, 

Fourth Edition, U.S. Department of Energy, Office of Fossil 

Energy, National Energy Technology Laboratory (NETL).
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assessment.401 The USGS estimates a mean of 3,000 billion metric 

tons of subsurface CO2 sequestration potential, including saline 

and oil and gas reservoirs, across the basins studied in the 

United States.

The DOE has created a network of seven Regional Carbon 

Sequestration Partnerships (RCSPs) to deploy large-scale field 

projects in different geologic settings across the country to 

demonstrate that GS can be achieved safely, permanently, and 

economically at large scales. Collectively, the seven RCSPs 

represent regions encompassing 97 percent of coal-fired CO2

emissions, 97 percent of industrial CO2 emissions, 96 percent of 

the total land mass, and essentially all the geologic 

sequestration sites in the United States potentially available 

for GS.402 The seven partnerships include more than 400 

organizations spanning 43 states (and four Canadian 

provinces).403 RCSP project objectives are to inject at least one 

million metric tons of CO2. In April 2015, DOE announced that CCS 

 

401 U.S. Geological Survey Geologic Carbon Dioxide Storage 

Resources Assessment Team, 2013, National assessment of geologic 

carbon dioxide storage resources—Results: U.S. Geological Survey 

Circular 1386, p. 41, http://pubs.usgs.gov/circ/1386/.

402 http://energy.gov/fe/science-innovation/carbon-capture-andstorage-research/regional-partnerships.

403 http://energy.gov/fe/science-innovation/carbon-capture-andstorage-research/regional-partnerships.
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projects supported by the department have safely and permanently 

stored 10 million metric tons of CO2.

404

Eight RCSP “Development Phase” projects have been initiated 

and five of the eight projects are injecting or have completed 

CO2 injection into deep saline formations. Three of these 

projects have already injected more than one million metric tons 

each, and one, the Cranfield Site, injected over eight million 

metric tons of CO2 between 2009 and 2013.405 Various types of 

technologies for monitoring CO2 in the subsurface and air have 

been employed at these projects, such as seismic methods 

(crosswell seismic, 3-D and 4-D seismic, and vertical seismic 

profiling), atmospheric CO2 monitoring, soil gas sampling, well 

and formation pressure monitoring, and surface and ground water 

monitoring.406 No CO2 leakage has been reported from these sites, 

which further supports the availability of effective GS.

 

404 http://energy.gov/articles/milestone-energy-departmentprojects-safely-and-permanently-store-10-million-metric-tons.

405 U.S. Department of Energy, National Energy Technology 

Laboratory, Project Facts, Southeast Regional Carbon 

Sequestration Partnership—Development Phase, Cranfield Site and 

Citronelle Site Projects, NT42590, October 2013. Available at: 

http://www.netl.doe.gov/publications/factsheets/project/NT42590.

pdf.

406 A description of the types of monitoring technologies 

employed at RCSP projects can be found here: 

http://www.netl.doe.gov/research/coal/carbon-storage/carbonstorage-infrastructure/regional-partnership-development-phaseiii.
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3. Availability of CO2 Storage via EOR

Although the determination that the BSER is adequately 

demonstrated and the regulatory impact analysis for this rule 

relies on GS in deep saline formations, the EPA also recognizes 

the potential for securely sequestering CO2 via EOR. 

EOR is a technique that is used to increase the production 

of oil. Approaches used for EOR include steam injection, 

injection of specific fluids such as surfactants and polymers, 

and gas injection including nitrogen and CO2. EOR using CO2, 

sometimes referred to as “CO2 flooding” or CO2-EOR, involves 

injecting CO2 into an oil reservoir to help mobilize the 

remaining oil to make it more amenable for recovery. The crude 

oil and CO2 mixture is then recovered and sent to a separator 

where the crude oil is separated from the gaseous hydrocarbons, 

native formation fluids, and CO2. The gaseous CO2-rich stream 

then is typically dehydrated, purified to remove hydrocarbons, 

re-compressed, and re-injected into the reservoir to further 

enhance oil recovery. Not all of the CO2 injected into the oil 

reservoir is recovered and re-injected. As the CO2 moves from the 

injection point to the production well, some of the CO2 becomes 

trapped in the small pores of the rock, or is dissolved in the 

oil and water that is not recovered. The CO2 that remains in the 

reservoir is not mobile and becomes sequestered. 
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The amount of CO2 used in an EOR project depends on the 

volume and injectivity of the reservoir that is being flooded 

and the length of time the EOR project has been in operation. 

Initially, all of the injected CO2 is newly received. As 

discussed above, as the project matures, some CO2 is recovered 

with the oil and the recovered CO2 is separated from the oil and 

recycled so that it can be re-injected into the reservoir in 

addition to new CO2 that is received. If an EOR operator will not 

require the full volume of CO2 available from an EGU, the EGU has 

other options such as sending the CO2 to other EOR operators, or 

sending it to deep saline formation GS facilities. 

CO2 used for EOR may come from anthropogenic or natural 

sources. The source of the CO2 does not impact the effectiveness 

of the EOR operation. CO2 capture, treatment and processing steps 

provide a concentrated stream of CO2 in order to meet the needs 

of the intended end use. CO2 pipeline specifications of the U.S. 

Department of Transportation Pipeline Hazardous Materials Safety 

Administration found at 49 CFR part 195 (Transportation of 

Hazardous Liquids by Pipeline) apply regardless of the source of 

the CO2 and take into account CO2 composition, impurities, and 

phase behavior. Additionally, EOR operators and transport 

companies have specifications related to the composition of the 

CO2 stream. The regulatory requirements and company 
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specifications ensure EOR operators receive a known and 

consistent CO2 stream.

EOR has been successfully used at numerous production 

fields throughout the United States to increase oil recovery. 

The oil industry in the United States has over 40 years of 

experience with EOR. An oil industry study in 2014 identified 

more than 125 EOR projects in 98 fields in the United States.407

More than half of the projects evaluated in the study have been 

in operation for more than 10 years, and many have been in 

operation for more than 30 years. This experience provides a 

strong foundation for demonstrating successful CO2 injection and 

monitoring technologies, which are needed for safe and secure GS 

(see Section N below) that can be used for deployment of CCS 

across geographically diverse areas. 

Currently, 12 states have active EOR operations and most 

have developed an extensive CO2 infrastructure, including 

pipelines, to support the continued operation and growth of EOR. 

An additional 18 states are within 100 kilometers (62 miles) of 

current EOR operations. See Figure 1 above. The vast majority of 

EOR is conducted in oil reservoirs in the Permian Basin, which 

extends through southwest Texas and southeast New Mexico. States 

 

407 Koottungal, Leena, 2014, 2014 Worldwide EOR Survey, Oil & Gas 

Journal, Volume 112, Issue 4, April 7, 2014 (corrected tables 

appear in Volume 112, Issue 5, May 5, 2014).
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where EOR is utilized include Alabama, Colorado, Louisiana, 

Michigan, Mississippi, New Mexico, Oklahoma, Texas, Utah, and 

Wyoming. Several commenters raised concerns about the volume of 

CO2 used in EOR projects relative to the scale of EGU emissions 

and the demand for CO2 for EOR projects. At the project level, 

the volume of CO2 already injected for EOR and the duration of 

operations are of similar magnitude to the duration and volume 

of CO2 expected to be captured from fossil fuel-fired EGUs. The 

volume of CO2 used in EOR operations can be large (e.g., 55 

million tons of CO2 were stored in the SACROC unit in the Permian 

Basin over 35 years), and operations at a single oil field may 

last for decades, injecting into multiple parts of the field.408

According to data reported to the EPA’s GHGRP, approximately 60 

million metric tons of CO2 were supplied to EOR in the United 

States in 2013.409 Approximately 70 percent of this total CO2

supplied was produced from natural (geologic) CO2 sources and 

approximately 30 percent was captured from anthropogenic 

sources.410

 

408 Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F P. 

“Evaluation of CO2 trapping mechanisms at the SACROC northern 

platform, Permian basin, Texas, site of 35 years of CO2

injection.” American Journal of Science 310. (2010): 282-324.

409 Greenhouse Gas Reporting Program, data reported as of August 

18, 2014.

410 Greenhouse Gas Reporting Program, data reported as of August 

18, 2014.
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A DOE-sponsored study has analyzed the geographic 

availability of applying EOR in 11 major oil producing regions 

of the United States and found that there is an opportunity to 

significantly increase the application of EOR to areas outside 

of current operations.411 DOE-sponsored geologic and engineering 

analyses show that expanding EOR operations into areas 

additional to the capacity already identified and applying new 

methods and techniques over the next 20 years could utilize 18 

billion metric tons of anthropogenic CO2 and increase total oil 

production by 67 billion barrels. The study found that one of 

the limitations to expanding CO2 use in EOR is the lack of 

availability of CO2 in areas where reservoirs are most amenable 

to CO2 flooding.412 DOE’s Carbon Utilization and Storage Atlas 

identifies 29 states with oil reservoirs amenable to EOR, 12 of 

which currently have active EOR operations. A comparison of the 

current states with EOR operations and the states with potential 

for EOR shows that an opportunity exists to expand the use of 

 

411 “Improving Domestic Energy Security and Lowering CO2 Emissions

with “Next Generation” CO2-Enhanced Oil Recovery”, Advanced 

Resources International, Inc. (ARI), 2011. Available at: 

http://www.netl.doe.gov/research/energyanalysis/publications/details?pub=df02ffba-6b4b-4721-a7b4-

04a505a19185.

412 “Improving Domestic Energy Security and Lowering CO2 Emissions 

with “Next Generation” CO2-Enhanced Oil Recovery”, Advanced 

Resources International, Inc. (ARI), 2011. Available at: 

http://www.netl.doe.gov/research/energyanalysis/publications/details?pub=df02ffba-6b4b-4721-a7b4-

04a505a19185.
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EOR to regions outside of current areas. The availability of 

anthropogenic CO2 in areas outside of current sources could drive 

new EOR projects by making more CO2 locally available. 

Some commenters raised concerns that data are extremely 

limited on the extent to which EOR operations permanently 

sequester CO2, and the efficacy of long term storage, or that the 

EOR industry does not have the requisite experience with and 

technical knowledge of long-term CO2 sequestration. The EPA 

disagrees with these commenters. Several EOR sites, which have 

been operated for years to decades, have been studied to 

evaluate the viability of safe and secure long-term 

sequestration of injected CO2. Examples are identified below.

CO2 has been injected in the SACROC Unit in the Permian 

basin since 1972 for EOR purposes. One study evaluated a portion 

of this project, and estimated that the injection operations 

resulted in final sequestration of about 55 million tons of 

CO2.

413 This study used modeling and simulations, along with 

collection and analysis of seismic surveys, and well logging 

data, to evaluate the ongoing and potential CO2 trapping 

occurring through various mechanisms. The monitoring at this 

site demonstrated that CO2 can become trapped in geologic 

 

413 Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F P. 

“Evaluation of CO2 trapping mechanisms at the SACROC northern 

platform, Permian basin, Texas, site of 35 years of CO2

injection.” American Journal of Science 310. (2010): 282-324.
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formations. In a separate study in the SACROC Unit, the Texas 

Bureau of Economic Geology conducted an extensive groundwater 

sampling program to look for evidence of CO2 leakage in the 

shallow freshwater aquifers. No evidence of leakage was 

detected.414

The International Energy Agency Greenhouse Gas Programme 

conducted an extensive monitoring program at the Weyburn oil 

field in Saskatchewan between 2000 and 2010 (the site receiving 

CO2 captured by the Dakota Gasification synfuel plant discussed 

in Section V.E.2.a above). During that time over 16 million 

metric tons of CO2 were safely sequestered as evidenced by soil 

gas surveys, shallow groundwater monitoring, seismic surveys and 

wellbore integrity testing. An extensive shallow groundwater 

monitoring program revealed no significant changes in water 

chemistry that could be attributed to CO2 storage operations.415

The International Energy Agency Greenhouse Gas Programme 

developed a best practices manual for CO2 monitoring at EOR sites 

 

414 Romanak, K.D., Smyth, R.C., Yang, C., and Hovorka, S., 

Detection of anthropogenic CO2 in dilute groundwater: field 

observations and geochemical modeling of the Dockum aquifer at 

the SACROC oilfield, West Texas, USA: presented at the 9th 

Annual Conference on Carbon Capture & Sequestration, Pittsburgh, 

PA, May 10-13, 2010. GCCC Digital Publication Series #10-06.

415 Roston, B., and S. Whittaker (2010), 10+ years of the IEA-GHG 

Weyburn-Midale CO2 monitoring and storage project; success and 

lessons learned from multiple hydrogeological investigations, to 

be published in Energy Procedia, Elsevier, Proceedings of 10th 

International Conference on Greenhouse Gas Control Technologies, 

IEA Greenhouse Gas Programme, Amsterdam, The Netherlands.
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based on the comprehensive analysis of surface and subsurface 

monitoring methods applied over the 10 years.416

The Texas Bureau of Economic Geology also has been testing 

a wide range of surface and subsurface monitoring tools and 

approaches to document sequestration efficiency and 

sequestration permanence at the Cranfield oilfield in 

Mississippi (see Section L.1 above).417 As part of a DOE 

Southeast Regional Carbon Sequestration Partnership study, 

Denbury Resources injected CO2 into a depleted oil and gas 

reservoir at a rate greater than 1.2 million tons/year. Texas 

Bureau of Economic Geology is currently evaluating the results 

of several monitoring techniques employed at the Cranfield 

project and preliminary findings indicate no impact to 

groundwater.418 The project also demonstrates the availability 

and effectiveness of many different monitoring techniques for 

tracking CO2 underground and detecting CO2 leakage to ensure CO2

remains safely sequestered. 

As discussed in Section M.1 above and as shown in Figure 1, 

the United States has widespread potential for storage, 

including in deep saline formations and oil and gas formations. 

However, some commenters maintained that the EPA’s information 

 

416 Hitchon, B. (Editor), 2012, Best Practices for Validating CO2

Geological Storage: Geoscience Publishing, p. 353.

417 http://www.beg.utexas.edu/gccc/cranfield.php.

418 http://www.beg.utexas.edu/gccc/cranfield.php.
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regarding availability of GS sites is overly general and ignores 

important individual considerations. A number of commenters, for 

example, maintained that site conditions often make monitoring 

difficult or impossible, so that sites are not available as a 

practical matter.419 Commenter American Electric Power pointed to 

its own experience in siting monitoring wells for its pilot 

plant Mountaineer CCS project, which involved protracted time 

and expense to eventually site monitoring wells.420 Other 

commenters noted significant geographic disparity in GS site 

availability, claiming absence of sites in southeastern areas of 

the country.421

Project- and site-specific factors do influence where CO2

can be safely sequestered. However, as outlined above, there is

widespread potential for GS in the United States. If an area 

does not have a suitable GS site, EGUs can either transport CO2

to GS sites via CO2 pipelines (see Section M.5 below), or they 

may choose to locate their units closer to GS sites and provide 

electric power to customers through transmission lines (see 

Figure 2 and Section M.7). In addition, there are alternative 

means of complying with the final standards of performance that

do not necessitate use of partial CCS, so any siting 

 

419 Comments of Southern Co., p. 38.

420 Comments of AEP pp. 93, 96.

421 Comments of Duke Energy, pp. 24-5; UARG, pp. 53, 57 citing 

Cichanowicz (2012).
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difficulties based on lack of a CO2 repository would be obviated. 

See Portland Cement Ass’n v. EPA, 665 F. 3d 177, 191 (D.C. Cir. 

2011), holding that the EPA could adopt section 111 standards of 

performance based on the performance of a kiln type that kilns 

of older design would have great difficulty satisfying, since,

among other things, there were alternative methods of compliance 

available should a new kiln of this older design be built.

4. Alternatives to Geologic Sequestration 

Potential alternatives to sequestering CO2 in geologic 

formations are emerging. These relatively new potential 

alternatives may offer the opportunity to offset the cost of CO2

capture. For example, captured anthropogenic CO2 may be stored in 

solid carbonate materials such as precipitated calcium carbonate 

(PCC) or magnesium or calcium carbonate, bauxite residue 

carbonation, and certain types of cement through mineralization. 

PCC is produced through a chemical reaction process that 

utilizes calcium oxide (quicklime), water, and CO2. Likewise, the 

combination of magnesium oxide and CO2 results in a precipitation 

reaction where the CO2 becomes mineralized. The carbonate 

materials produced can be tailored to optimize performance in 

specific industrial and commercial applications. These carbonate 

materials have been used in the construction industry and, more 

recently and innovatively, in cement production processes to 

replace Portland cement.
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The Skyonics Skymine project, which opened its 

demonstration project in October 2014, is an example of captured 

CO2 being used in the production of carbonate products. This 

plant converts CO2 into commercial products. It captures over 

75,000 tons of CO2 annually from a San Antonio, Texas, cement 

plant and converts the CO2 into other products, including sodium 

carbonate, sodium bicarbonate, hydrochloric acid and bleach.422

A few commenters suggested that CO2 utilization technologies 

alternative to GS are being commercialized, and that these 

should be included as compliance options for this rule. The rule 

generally requires that captured CO2 be either injected on-site 

for geologic sequestration or transferred offsite to a facility 

reporting under 40 CFR subpart RR. The EPA does not believe that 

the emerging technologies just discussed are sufficiently 

advanced to unqualifiedly structure this final rule to allow for 

their use. Nor are there plenary systems of regulatory control 

and GHG reporting for these approaches, as there are for 

geologic sequestration. Nonetheless, as stated above, these 

technologies not only show promise, but could potentially be 

demonstrated to show permanent storage of CO2.

In the January 2014 proposal, the EPA noted that it would 

need to adopt a mechanism to evaluate these alternative 

 

422 http://skyonic.com/technologies/skymine.
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technologies before any could be used in lieu of geologic 

sequestration. 79 FR at 1484. The EPA is establishing such a 

mechanism in this final rule. See §60.5555(g). The rule provides 

for a case-by-case adjudication by the EPA of applications 

seeking to demonstrate to the EPA that a non-geologic 

sequestration technology would result in permanent confinement 

of captured CO2 from an affected EGU. The criteria to be 

addressed in the application, and evaluated by the EPA, are 

drawn from CAA section 111(j), which provides an analogous 

mechanism for case-by-case approval of innovative technological 

systems of continuous emission reduction which have not been 

adequately demonstrated. Applicants would need to demonstrate

that the proposed technology would operate effectively, and that 

captured CO2 would be permanently stored. Applicants must also 

demonstrate that the proposed technology will not cause or 

contribute to an unreasonable risk to public health, welfare or 

safety. In evaluating applications, the EPA may conduct tests 

itself or require the applicant to conduct testing in support of 

its application. Any application would be publicly noticed, and 

the EPA would solicit comment on the application and on intended 

action the EPA might take. The EPA could also provide a 

conditional approval of an application on operating results from 

a proscribed period. The EPA could also terminate an approval, 
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including a termination based on operating results calling into 

question a technology’s effectiveness.

As noted at proposal, given the unlikelihood of new coalfired EGUs being constructed, the EPA does not expect there to 

be many (if any) applications for use of non-geologic 

sequestration technology. 79 FR at 1484. 

5. Availability of Existing or Planned CO2 Pipelines

CO2 pipelines are the most economical and efficient method 

of transporting large quantities of CO2.

423 CO2 has been 

transported via pipelines in the United States for nearly 40 

years. Over this time, the design, construction, operation, and 

safety requirements for CO2 pipelines have been proven, and the 

U.S. CO2 pipeline network has been safely used and expanded. The 

Pipeline and Hazardous Materials Safety Administration (PHMSA) 

reported that in 2013 there were 5,195 miles of CO2 pipelines 

operating in the United States. This represents a seven percent 

increase in CO2 pipeline miles over the previous year and a 38 

percent increase in CO2 pipeline miles since 2004.424

 

423 Report of the Interagency Task Force on Carbon Capture and 

Storage (August 2010), page 36.

424 “Annual Report Mileage for Hazardous Liquid or Carbon Dioxide 

Systems”, U.S. Pipeline and Hazardous Materials Safety 

Administration, March 2, 2015. Available at:

http://www.phmsa.dot.gov/pipeline/library/data-stats. 
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Some commenters argued that the existing CO2 pipeline 

capacity is not adequate and that CO2 pipelines are not available 

in a majority of the United States. 

The EPA does not agree. The CO2 pipeline network in the 

United States has almost doubled in the past ten years in order 

to meet growing demands for CO2 for EOR. CO2 transport companies 

have recently proposed initiatives to expand the CO2 pipeline 

network. Several hundred miles of dedicated CO2 pipeline are 

under construction, planned, or proposed, including projects in 

Colorado, Louisiana, Montana, New Mexico, Texas, and Wyoming. 

Examples are identified below.

Kinder Morgan has reported several proposed pipeline 

projects including the proposed expansion of the existing Cortez 

CO2 pipeline, crossing Colorado, New Mexico, and Texas, to 

increase the CO2 transport capacity from 1.35 billion cubic feet 

per day (Bcf/d) to 1.7 Bcf/d, to support the expansion of CO2

production capacity at the McElmo Dome production facility in 

Colorado. The Cortez pipeline expansion is expected to be placed 

into service in 2015.425

 

425 “Form 10-K: Annual Report Pursuant to Section 13 or 15(d) of 

the Security and Exchange Act of 1934, For the Fiscal Year Ended 

December 31, 2014”, Kinder Morgan, February 2015. Available at: 

http://ir.kindermorgan.com/sites/kindermorgan.investorhq.busines

swire.com/files/report/additional/KMI-2014-10K_Final.pdf.
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Denbury reported that the company utilized approximately 70 

million cubic feet per day of anthropogenic CO2 in 2013 and that 

an additional approximately 115 million cubic feet per day of 

anthropogenic CO2 may be utilized in the future from currently 

planned or future construction of facilities and associated 

pipelines in the Gulf Coast region.426 Denbury also initiated 

transport of CO2 from a Wyoming natural gas processing plant in 

2013 and reported transporting approximately 22 million cubic 

feet per day of CO2 in 2013 from that plant alone.427

Denbury completed the final section of the 325-mile Green 

Pipeline for transporting CO2 from Donaldsonville, Louisiana, to 

EOR oil fields in Texas.428 Denbury completed construction and 

commenced operation of the 232-mile Greencore Pipeline in 2013; 

the Greencore pipeline transports CO2 to EOR fields in Wyoming 

and Montana.429

A project being constructed by NRG and JX Nippon Oil & Gas 

Exploration (Petra Nova) would capture CO2 from a power plant in 

 

426 “2013 Annual Report”, Denbury, April 2014. Available at 

http://www.denbury.com/files/doc_financials/2013/Denbury_Final_0

40814.pdf.

427 “CO2 Sources”, Denbury, 2015. Available at:

http://www.denbury.com/operations/rocky-mountain-region/co2-

sources-and-pipelines/default.aspx. 

428 http://www.denbury.com/operations/gulf-coastregion/Pipelines/default.aspx.

429 “CO2 Pipelines”, Denbury, 2014. Available at: 

http://www.denbury.com/operations/rocky-mountain-region/COsub2-

sub-Pipelines/default.aspx.
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Fort Bend County, Texas for transport to EOR sites in Jackson 

County, Texas through an 82-mile CO2 pipeline.430 The project is 

anticipated to commence operation in 2016.431

Some commenters suggested that there may be challenges

associated with the safety of transporting supercritical CO2 over 

long distances, or that the EPA did not adequately consider the 

potential non-air environmental impacts of the construction of 

CO2 pipelines.

The EPA has carefully evaluated the safety of pipelines 

used to transport captured CO2 and determined that pipelines can 

indeed convey captured CO2 to sequestration sites with certainty 

and provide full protection of human health and the environment. 

76 FR at 48082-83 (Aug. 8, 2011); 79 FR 352, 354 (Jan. 3, 2014).

Existing and new CO2 pipelines are comprehensively regulated by 

the Department of Transportation’s Pipeline Hazardous Material 

Safety Administration. The regulations govern pipeline design, 

construction, operation and maintenance, and emergency response 

planning. See generally 49 CFR 195.2. Additional regulations 

address pipeline integrity management by requiring heightened 

scrutiny to assure the quality of pipeline integrity in areas 

 

430 “The West Ranch CO2-EOR Project, NRG Fact Sheet”, NRG, 2014. 

Available at: www.nrg.com/documents/business/pla-2014-westranch-fact-sheet.pdf. 

431 “WA Parish Carbon Capture Project”, NRG, 2015. Available at: 

www.nrg.com/sustainability/strategy/enhance-generation/carboncapture/wa-parish-ccs-project/.
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with a higher potential for adverse consequences. See 49 CFR 

195.450 and 195.452. On-site pipelines are not subject to the 

Department of Transportation standards, but rather adhere to the 

Pressure Piping standards of the American Society of Mechanical 

Engineers (ASME B31), which the EPA has found would ensure that 

piping and associated equipment meet certain quality and safety 

criteria sufficient to prevent releases of CO2, such that certain 

additional requirements were not necessary (See 79 FR 358-59 

(Jan. 3, 2014)).433 These existing controls over CO2 pipelines 

assure protective management, guard against releases, and assure 

that captured CO2 will be securely conveyed to a sequestration

site. 

6. States with Emission Standards That Would Require CCS

Several states have established emission performance 

standards or other measures to limit emissions of GHGs from new 

EGUs that are comparable to or more stringent than the final 

standard in this rulemaking. For example, in September 2006, 

California Governor Schwarzenegger signed into law Senate Bill 

1368. The law limits long-term investments in base load 

generation by the state’s utilities to power plants that meet an 

emissions performance standard jointly established by the 

 

433 See the B31 Code for pressure piping, developed by the 

American Society of Mechanical Engineers, Pipeline 

Transportation Systems for liquid hydrocarbons and other 

liquids.
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California Energy Commission and the California Public Utilities 

Commission. The Energy Commission has designed regulations that 

establish a standard for new and existing base load generation 

owned by, or under long-term contract to publicly owned 

utilities, of 1,100 lb CO2/MWh.

In May 2007, Washington Governor Gregoire signed Substitute 

Senate Bill 6001, which established statewide GHG emissions 

reduction goals, and imposed an emission standard that applies 

to any base load electric generation that commenced operation 

after June 1, 2008 and is located in Washington, whether or not 

that generation serves load located within the state. Base load 

generation facilities must initially comply with an emission 

limit of 1,100 lb CO2/MWh.

In July 2009, Oregon Governor Kulongoski signed Senate Bill 

101, which mandated that facilities generating base load 

electricity, whether gas- or coal-fired, must have emissions 

equal to or less than 1,100 lb CO2/MWh, and prohibited utilities 

from entering into long-term purchase agreements for base load 

electricity with out-of-state facilities that do not meet that 

standard.

In 2012 New York established emission standards of CO2 at 

925 lb CO2/MWh for new and expanded base load fossil fuel-fired 

plants.
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In May 2007, Montana Governor Schweitzer signed House Bill 

25, adopting a CO2 emissions performance standard for EGUs in the 

state. House Bill 25 prohibits the state Public Utility 

Commission from approving new EGUs primarily fueled by coal 

unless a minimum of 50 percent of the CO2 produced by the 

facility is captured and sequestered.

On January 12, 2009, Illinois Governor Blagojevich signed 

Senate Bill 1987, the Clean Coal Portfolio Standard Law. The 

legislation establishes emission standards for new power plants 

that use coal as their primary feedstock. From 2009–2015, new 

coal-fueled power plants must capture and store 50 percent of 

the carbon emissions that the facility would otherwise emit; 

from 2016–2017, 70 percent must be captured and stored; and 

after 2017, 90 percent must be captured and stored.

7. Coal-by-wire

In addition, as discussed in the proposal, electricity 

demand in states that may not have geologic sequestration sites 

may be served by coal-fired electricity generation built in 

nearby areas with geologic sequestration, and this electricity

can be delivered through transmission lines. This method, known 

as “coal-by-wire,” has long been used in the electricity sector 

because siting a coal-fired power plant near the coal mine and 

transmitting the generation long distances to the load area is 
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generally less expensive than siting the plant near the load 

area and shipping the coal long distances.

For example, we noted in the proposal: “There are many 

examples where coal-fired power generated in one state is used 

to supply electricity in other states. For instance, 

historically, nearly 40 percent of the power for the City of Los 

Angeles was provided from two coal-fired power plants located in 

Arizona and Utah. In another example, Idaho Power, which serves 

customers in Idaho and Eastern Oregon, meets its demand in part 

from coal-fired power plants located in Wyoming and Nevada.” 79

FR at 1478.

In the Technical Support Document on Geographic 

Availability (Geographic Availability TSD), we explore in 

greater detail the issue of coal-by-wire and the ability of 

demand in areas without geologic sequestration to be served by 

coal generation located in areas that have access to geologic 

sequestration. Figure 1 of this preamble (a color version of 

which is provided as Figure 1 of the Geographic Availability 

TSD) depicts areas of the country with: (1) existing CO2

pipeline; (2) probable, planned, or under study CO2 pipeline; (3) 

counties with active CO2-EOR operations; (4) oil and natural gas 

reservoirs; (5) deep saline formations; (6) unmineable coal 

seams; and (7) areas 100 kilometers from geologic sequestration. 

As demonstrated by Figure 1, the vast majority of the country 
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has existing or planned CO2 pipeline, active CO2-EOR operations, 

the necessary geology for CO2 storage, or is within 100 

kilometers of areas with geologic sequestration.434 A review of 

Figure 1 indicates limited areas that do not fall into these 

categories. 

As an initial matter, we note that the data included in 

Figure 1 is a conservative outlook of potential areas available 

for the development of CO2 storage in that we include only areas 

that have been assessed to date. Portions of the United States –

such as the State of Minnesota -- have not yet been assessed and 

thus are depicted as not having geological formations suitable 

for CO2 storage, even though assessment could in fact reveal 

additional formations.435

As one considers the areas on the map depicted in Figure 1 

that fall outside of the above enumerated categories, in many 

instances, we find areas with low population density, areas that 

 

434 The NETL cost estimates for CO2 transport assume a pipeline of 

100 kilometers. NETL (2015) at p. 44.

435 The data in Figure 1 is based on estimates compiled by the 

DOE’s National Carbon Sequestration Database and Geographic 

Information System (NATCARB) and published in the United States 

2012 Carbon Utilization and Storage Atlas, Fourth Edition. As 

discussed in the TSD, deep saline formation potential was not 

assessed for Alaska, Connecticut, Hawaii, Massachusetts, Nevada, 

Rhode Island, and Vermont. Oil and gas storage potential was not 

assessed for Alaska, Washington, Nevada, and Oregon. Unmineable 

coal seams were not assessed for Nevada, Oregon, California, 

Idaho, and New York. We are assuming for purposes of our 

analysis here that they do not have storage potential in those 

formations.
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are already served by transmission lines that could deliver 

coal-by-wire, and/or areas that have made policy or other 

decisions not to pursue a resource mix that includes coal. In 

many of these areas, utilities, electric cooperatives, and 

municipalities have a history of joint ownership of coal-fired 

generation outside the region or contracting with coal and other 

generation in outside areas to meet their demand. Some of the 

relevant areas are in RTOs436 which engage in planning across the 

RTO, balancing supply and demand in real time throughout the 

RTO. Accordingly, generating resources in one part of the RTO 

such as a coal generator can serve load in other parts of the 

RTO, as well as load outside of the RTO. As we consider each of 

these geographic areas in the Geographic Availability TSD, we 

make key points as to why this final rule does not negatively 

impact the ability of these regions to access new coal 

generation to the extent that coal is needed to supply demand 

and/or those regions want to include new coal-fired generation 

in their resource mix.

N. Final Requirements for Disposition of Captured CO2

This section discusses the different regulatory components, 

already in place, that assure the safety and effectiveness of 

GS. This section, by demonstrating that GS is already covered by 

 

436 In this discussion, we use the term RTO to indicate both ISOs 

and RTOs.
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an effective regulatory structure, complements the analysis of 

the technical feasibility of GS contained in Sec. V.M. Together, 

these sections affirm that the technical feasibility of GS is 

adequately demonstrated.

In 2010, the EPA finalized an effective and coherent 

regulatory framework to ensure the long-term, secure and safe 

storage of large volumes of CO2. The EPA developed these 

Underground Injection Control (UIC) Class VI well regulations 

under authority of the Safe Drinking Water Act (SDWA) to 

facilitate injection of CO2 for GS, while protecting human health 

and the environment by ensuring the protection of underground 

sources of drinking water (USDWs). The Class VI regulations are 

built upon 35 years of federal experience regulating underground 

injection wells, and many additional years of state UIC program 

expertise. The EPA and states have decades of UIC experience 

with the Class II program, which provides a regulatory framework 

for the protection of USDWs for CO2 injected for purposes of EOR.

In addition, to complement both the Class VI and Class II

rules, the EPA used CAA authority to develop air-side monitoring 

and reporting requirements for CO2 capture, underground 

injection, and geologic sequestration through the GHGRP.

Information collected under the GHGRP provides a transparent 

means for the EPA and the public to continue to evaluate the 

effectiveness of GS. 
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As explained below, these requirements help ensure that 

sequestered CO2 will remain in place, and, using SDWA and CAA 

authorities, provide the monitoring mechanisms to identify and 

address potential leakage. We note the near consensus in the

public responses to the Class VI rulemaking that saline and oil 

and gas reservoirs provide ready means for secure GS of CO2.

437

1. Requirements for UIC Class VI and Class II Wells

Under SDWA, the EPA developed the UIC Program to regulate 

the underground injection of fluids in a manner that ensures 

protection of USDWs. UIC regulations establish six different 

well classes that manage a range of injectates (e.g., industrial 

and municipal wastes; fluids associated with oil and gas 

activities; solution mining fluids; and CO2 for geologic 

sequestration) and which accommodate varying geologic, 

hydrogeological, and other conditions. The standards apply to 

injection into any type of formation that meets the rule’s 

rigorous criteria, and so apply not only to injection into deep 

saline formations, but also can apply to injection into 

 

437 “Most commenters encouraged the EPA not to automatically 

exclude any potential injection formations for GS at this stage 

of deployment. Commenters suggested, in particular, that there 

is sufficient technical basis and scientific evidence to allow 

GS in depleted oil and gas reservoirs and in saline formations, 

noting that there is consensus on how to inject into these 

formation types.” 75 FR at 77252 (Dec. 10, 2010).
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unmineable coal seams and other formations. See 75 FR 77256 

(Dec. 10, 2010). 

The EPA's UIC regulations define the term USDWs to include 

current and future sources of drinking water and aquifers that

contain a sufficient quantity of ground water to supply a public 

water system, where formation fluids either are currently being 

used for human consumption or that contain less than 10,000 ppm 

total dissolved solids.438 UIC requirements have been in place 

for over three decades and have been used by the EPA and states 

to manage hundreds of thousands of injection wells nationwide.

a. Class VI requirements

In 2010, the EPA established a new class of well, Class VI. 

Class VI wells are used to inject CO2 into the subsurface for the 

purpose of long-term sequestration. See 75 FR 77230 (Dec. 10, 

2010). This rule accounts for the unique nature of CO2 injection 

for large-scale GS. Specifically, the EPA addressed the unique 

characteristics of CO2 injection for GS including the large CO2

injection volumes anticipated at GS projects, relative buoyancy 

of CO2, its mobility within subsurface geologic formations, and 

its corrosivity in the presence of water. The UIC Class VI rule 

was developed to facilitate GS and ensure protection of USDWs 

from the particular risks that may be posed by large scale CO2

 

438 40 CFR §144.3.
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injection for purposes of long-term GS. The Class VI rule 

establishes technical requirements for the permitting, geologic 

site characterization, area of review (i.e., the project area) 

and corrective action, well construction, operation, mechanical 

integrity testing, monitoring, well plugging, post-injection 

site care, site closure, and financial responsibility for the 

purpose of protecting USDWs.439 Notably:

Site characterization includes assessment of the geologic, 

hydrogeologic, geochemical, and geomechanical properties of a 

proposed GS site to ensure that Class VI wells are sited in 

 

439 The Class VI rule rests on a robust technical and scientific 

foundation, reflecting scientific oversight and peer review. 

In developing these Class VI rules, the EPA engaged with the 

SAB, providing detailed information on key issues relating to 

geologic sequestration – including monitoring schemes; methods 

to predict and verify capacity, injectivity, and effectiveness 

of subsurface CO2 storage; and characterization and management of 

risks associated with plume migration and pressure increases in 

the subsurface. See: 

http://yosemite.epa.gov/sab/sabproduct.nsf/0/AD09B42B75D9E36D852

57704004882CF?OpenDocument. In addition, the EPA developed a 

peer reviewed Vulnerability Evaluation Framework, which served 

as a technical support document for both the Class VI and 

Subpart RR rules. See: 

http://www.epa.gov/climatechange/Downloads/ghgemissions/VEFTechnical_Document_072408.pdf. In the section 111 (b) rulemaking 

here, the SAB Work Group, in a letter endorsed by the full SAB 

Committee, found that “while the scientific and technical basis 

for carbon storage provisions is new and emerging science, the 

agency is using the best available science and has conducted 

peer review at a level required by agency guidance.” Memorandum 

of Jan. 7, 2014, from SAB Work Group Chair to Members of the 

Chartered SAB and SAB Liaisons, p. 3. The letter was 

subsequently endorsed by the full SAB. Work Group Letter of Jan. 

24, 2014, as edited by the full Committee.
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appropriate locations and CO2 streams are injected into suitable 

formations with a confining zone or zones free of transmissive 

faults or fractures to ensure USDW protection.440,441 Site 

characterization is designed to eliminate unacceptable sites 

that may pose risks to USDWs. Generally, injection of CO2 for GS 

should occur beneath the lowermost formation containing a 

USDW.442 To increase the availability of Class VI sites in 

geographic areas with very deep USDWs, waivers from the 

injection depth requirements may be sought where owners or 

operators can demonstrate USDW protection.443

Owners or operators of Class VI wells must delineate the 

project area of review using computational modeling that 

accounts for the physical and chemical properties of the 

injected CO2 and displaced fluids and is based on an iterative 

process of available site characterization, monitoring, and 

operational data.444 Within the area of review, owners or 

operators must identify and evaluate all artificial penetrations 

to identify those that need corrective action to prevent the 

 

440 75 FR 77240 and 75 FR 77247 (December 10, 2010).

441 40 CFR §146.82 and §146.83. Comments indicating that EPA 

rules have not considered issues of exposure pathways such as 

abandoned wells or formation fissures are mistaken. (See, e.g., 

Comments of UARG, p. 52.)

442 40 CFR §146.81(d).

443 40 CFR §146.95.

444 40 CFR §146.84(a).
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movement of CO2 or other fluids into or between USDWs.445,446 Due 

to the potentially large size of the area of review for Class VI 

wells, corrective actions may be conducted on a phased basis 

during the lifetime of the project.447 Periodic reevaluation of 

the area of review is required and enables owners or operators 

to incorporate previously collected monitoring and operational 

data to verify that the CO2 plume and the associated area of 

elevated pressure are moving as predicted within the 

subsurface.448

Well construction must use materials that can withstand 

contact with CO2 over the operational and post-injection life of 

the project.449 These requirements address the unique physical 

characteristics of CO2, including its buoyancy relative to other 

fluids in the subsurface and its potential corrosivity in the 

presence of water.

Requirements for operation of Class VI injection wells 

account for the unique conditions that will occur during largescale GS including buoyancy, corrosivity, and high sustained 

pressures over long periods of operation.450,451

 

445 40 CFR §146.84(c)(1)(3) and §146.90(d)(1).

446 40 CFR §146.81(d) and §146.84.

447 40 CFR §146.84(b)(2)(iv).

448 40 CFR §146.84(e)(1).

449 40 CFR §146.86(b).

450 75 FR 77250-52 (December 10, 2010); see also id. at 77234-35. 

Commenters were mistaken in asserting (without reference to 
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Owners or operators of Class VI wells must develop and 

implement a comprehensive testing and monitoring plan for their 

projects that includes injectate analysis, mechanical integrity 

testing, corrosion monitoring, ground water and geochemical 

monitoring, pressure fall-off testing, CO2 plume and pressure 

front monitoring and tracking, and, at the discretion of the 

Class VI director, surface air and/or soil gas monitoring.452

Owners and operators must periodically review the testing and 

monitoring plan to incorporate operational and monitoring data 

and the most recent area of review reevaluation.453 Robust 

monitoring of the CO2 stream, injection pressures, integrity of 

the injection well, ground water quality and geochemistry, and 

monitoring of the CO2 plume and position of the pressure front 

throughout injection will ensure protection of USDWs from 

endangerment, preserve water quality, and allow for timely 

detection of any leakage of CO2 or displaced formation fluids. 

Although subsurface monitoring is the primary and effective 

means of determining if there are any risks to a USDW, the Class 

VI rule also authorizes the UIC Program Director to require 

surface air and/or soil gas monitoring on a site-specific basis. 

 

Class VI provisions) that the EPA had ignored issues relating to 

CO2 properties when injected in large volumes in supercritical 

state into geologic formations.

451 40 CFR §146.88.

452 40 CFR §146.90.

453 40 CFR §146.90(j).
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For example, the Class VI Director may require surface air/soil 

gas monitoring of the flux of CO2 out of the subsurface, with 

elevation of CO2 levels above background serving as an indicator 

of potential leakage and USDW endangerment.454

Class VI well owners or operators must develop and update a 

site-specific, comprehensive emergency and remedial response 

plan that describes actions to be taken (e.g., cease injection) 

to address potential events that may cause endangerment to a 

USDW during the construction, operation, and post-injection site 

care periods of the project.455

Financial responsibility demonstrations are required to 

ensure that funds will be available for all area of review 

corrective action, injection well plugging, post-injection site 

care, site closure, and emergency and remedial response.456

Following cessation of injection, the operator must conduct 

comprehensive post-injection site care activities to show the 

position of the CO2 plume and the associated area of elevated 

pressure to demonstrate that neither poses an endangerment to 

USDWs.457 The injection well also must be plugged, and following 

a demonstration of non-endangerment of USDWs by the Class VI 

 

454 40 CFR §146.90(h)(1) and 75 FR at 77259 (Dec. 10, 2010).

455 40 CFR §146.94.

456 40 CFR §146.85.

457 40 CFR §146.93.
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owner or operator, the site must be closed.458,459 The default 

duration for the post-injection site care period is 50 years, 

with flexibility for demonstrating that an alternative period is 

appropriate if it ensures non-endangerment of USDWs.460 Following 

successful closure, the facility property deed must record that 

the underlying land is used for GS.461

The EPA has completed technical guidance documents on Class 

VI well site characterization, area of review and corrective 

action, well testing and monitoring, project plan development, 

well construction, and financial responsibility.462,463,464,465,466,467

The EPA has also issued guidance documents on transitioning 

Class II wells to Class VI wells; well plugging, post-injection 

 

458 40 CFR §146.92.

459 40 CFR §146.93.

460 40 CFR §146.93(b).

461 40 CFR §146.93(c).

462

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r1

3004.pdf.

463

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r1

3005.pdf.

464

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r1

3001.pdf.

465

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r1

1017.pdf.

466

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r1

1020.pdf.

467

http://water.epa.gov/type/groundwater/uic/class6/upload/uicfinan

cialresponsibilityguidancefinal072011v.pdf.
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site care, and site closure; and recordkeeping, reporting, and 

data management.468,469,470,471

To inform the development of the UIC Class VI rule, the EPA 

solicited stakeholder input and reviewed ongoing domestic and 

international GS research, demonstration, and deployment 

projects. The EPA also leveraged injection experience of the UIC 

Program, such as injection via Class II wells for EOR. A 

description of the work conducted by the EPA in support of the 

UIC Class VI rule can be found in the preamble for the final 

rule (see 75 FR 77230 and 77237-240(December 10, 2010)).

The EPA has issued Class VI permits for six wells under two 

projects. In September 2014, a UIC Class VI injection well 

permit (to construct) was issued by the EPA to Archer Daniels 

Midland for an ethanol facility in Decatur, Illinois. The goal 

 

468

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p1

3004.pdf. See also 40 CFR §144.19 and “Key Principles in EPA’s 

Underground Injection Control Program Class VI Rule Related to 

Transition of Class II Enhanced Oil Recovery or Gas Recovery 

Wells to Class VI”, April 23, 2015, Available at: 

http://water.epa.gov/type/groundwater/uic/class6/upload/class2eo

rclass6memo.pdf.

469

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p1

3005.pdf.

470

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p1

3001.pdf.

471

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p1

3002.pdf.
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of the project is to demonstrate the ability of the Mount Simon 

geologic formation, a deep saline formation, to accept and 

retain industrial scale volumes of CO2 for permanent GS. The 

permitted well has a projected operational period of five years, 

during which time 5.5 million metric tons of CO2 will be injected 

into an area of review with a radius of approximately 2 miles.472

Following the operational period, Archer Daniels Midland plans a 

post-injection site care period of ten years.473 In September 

2014, the EPA also issued four Class VI injection well permits 

(to construct) to the FutureGen Industrial Alliance project in 

Jacksonville, Illinois, which proposed to capture CO2 emissions 

from a coal-fired power plant in Meredosia, Illinois and 

transport the CO2 by pipeline approximately 30 miles to the deep 

saline GS site.474 The Alliance proposed to inject a total of 22 

million metric tons of CO2 into an area of review with a radius 

of approximately 24 miles over the 20 year life of the project, 

with a post-injection site care period of fifty years.475

 

472 http://www.epa.gov/region5/water/uic/adm/. In addition, 

Archer Daniels Midland received a UIC Class VI injection well 

permit for a second well in December 2014. Archer Daniels 

Midland had been injecting CO2 at this well since 2011 under a 

UIC Class I permit issued by the Illinois EPA.

473 http://www.epa.gov/region5/water/uic/adm/.

474 After permit issuance, and for reasons unrelated to the 

permitting proceeding, DOE initiated a structured closeout of 

federal support for the FutureGen project in February 2015. 

However, these are still active Class VI permits.

475 http://www.epa.gov/r5water/uic/futuregen/.
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Both permit applicants addressed siting and operational 

aspects of GS (including issues relating to volumes of the CO2

and nature of the CO2 injectate), and included monitoring that 

helps provide assurance that CO2 will not migrate to shallower 

formations. The permits were based on findings that regional and 

local features at the site allow the site to receive injected CO2

in specified amounts without buildup of pressure which would 

create faults or fractures, and further, that monitoring 

provides early warning of any changes to groundwater or CO2

leakage.476

The permitting of these projects illustrates that permit 

applicants were able to address perceived challenges to issuance 

of Class VI permits. These permits demonstrate that these 

projects are capable of safely and securely sequestering large 

volumes of CO2 - including from steam generating units - for 

long-term storage since the EPA would not otherwise have issued 

the permits. 

b. Class II requirements

As explained in Section M.3 above, CO2 has been injected 

into the subsurface via injection wells for EOR, boosting 

production efficiency by re-pressurizing oil and gas reservoirs 

and increasing the mobility of oil. There are decades of 

 

476 http://www.epa.gov/r5water/uic/futuregen/;

http://www.epa.gov/region5/water/uic/adm/.
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industry experience in operating EOR projects. The CO2 injection 

wells used for EOR are regulated through the UIC Class II 

program.

477 CO2 storage associated with Class II wells is a common 

occurrence and CO2 can be safely stored where injected through 

Class II-permitted wells for the purpose of enhanced oil or gasrelated recovery.

UIC Class II regulations issued under section 1421 of SDWA 

provide minimum federal requirements for site characterization, 

area of review, well construction (e.g., casing and cementing), 

well operation (e.g., injection pressure), injectate sampling, 

mechanical integrity testing, plugging and abandonment, 

financial responsibility, and reporting. Class II wells must 

undergo periodic mechanical integrity testing which will detect 

well construction and operational conditions that could lead to 

loss of injectate and migration into USDWs.

Section 1425 of SDWA allows states to demonstrate that 

their program is effective in preventing endangerment of USDWs. 

These programs must include permitting, inspection, monitoring, 

record-keeping, and reporting components.

2. Relevant Requirements of the GHGRP

The GHGRP requires reporting of facility-level GHG data and 

other relevant information from large sources and suppliers in 

 

477 40 CFR §144.6(b).
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the United States. The final rules under 40 CFR part 60

specifically require that if an affected EGU captures CO2 to meet 

the applicable emissions limit, the EGU must report in 

accordance with 40 CFR part 98, subpart PP (Suppliers of Carbon 

Dioxide) and the captured CO2 must be injected at a facility or 

facilities that reports in accordance with 40 CFR part 98,

subpart RR (Geologic Sequestration of Carbon Dioxide). See

§60.5555(f). Taken together, these requirements ensure that the 

amount of captured and sequestered CO2 will be tracked as 

appropriate at project- and national-levels, and that the status 

of the CO2 in its sequestration site will be monitored, including 

air-side monitoring and reporting.

Specifically, subpart PP provides requirements to account 

for CO2 supplied to the economy. This subpart requires affected 

facilities with production process units that capture a CO2

stream for purposes of supplying CO2 for commercial applications 

or that capture and maintain custody of a CO2 stream in order to 

sequester or otherwise inject it underground to report the mass 

of CO2 captured and supplied to the economy.478 CO2 suppliers are 

required to report the annual quantity of CO2 transferred offsite 

and its end use, including GS.479

 

478 40 CFR §98.420(a)(1).

479 40 CFR §98.426.
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This rule finalizes amendments to subpart PP reporting 

requirements, specifically requiring that the following pieces 

of information be reported: (1) the electronic GHG Reporting 

Tool identification (e-GGRT ID) of the EGU facility from which 

CO2 was captured, and (2) the e-GGRT ID(s) for, and mass of CO2

transferred to, each GS site reporting under subpart RR.480

As noted, this final rule also requires that any affected 

EGU unit that captures CO2 to meet the applicable emissions limit 

must transfer the captured CO2 to a facility that reports under 

GHGRP subpart RR. In order to provide clarity on this 

requirement, the EPA reworded the proposed language under 

§60.5555(f) to use the phrase “If your affected unit captures 

CO2” in place of the phrase “If your affected unit employs 

geologic sequestration”. This revision is not a change from the 

EPA’s initial intent. 

Reporting under subpart RR is required for all facilities 

that have received a Class VI UIC permit for injection of CO2.

481

Subpart RR requires facilities meeting the source category 

definition (40 CFR 98.440) for any well or group of wells to 

report basic information on the mass of CO2 received for 

injection; develop and implement an EPA-approved monitoring, 

reporting, and verification (MRV) plan; report the mass of CO2

 

480 40 CFR §98.426(h).

481 40 CFR §98.440.
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sequestered using a mass balance approach; and report annual 

monitoring activities.482,483,484,485 Although deep subsurface 

monitoring is the primary and effective means of determining if 

there are any leaks to a USDW, the monitoring employed under a 

subpart RR MRV Plan can be utilized, if required by the UIC 

Program Director, to further ensure protection of USDWs.486 The 

subpart RR MRV plan includes five major components:

A delineation of monitoring areas based on the CO2 plume 

location. Monitoring may be phased in over time.487

An identification and evaluation of the potential surface 

leakage pathways and an assessment of the likelihood, magnitude, 

and timing, of surface leakage of CO2 through these pathways. The 

monitoring program will be designed to address the risks 

identified.488

A strategy for detecting and quantifying any surface 

leakage of CO2 in the event leakage occurs. Multiple monitoring 

methods and accounting techniques can be used to address changes 

in plume size and risks over time.489

 

482 40 CFR §98.446.

483 40 CFR §98.448.

484 40 CFR §98.446(f)(9) and (10).

485 40 CFR §98.446(f)(12).

486 See 75 FR at 77263 (Dec. 10, 2010). 

487 40 CFR §98.448(a)(1).

488 40 CFR §98.448(a)(2).

489 40 CFR §98.448(a)(3).
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An approach for establishing the expected baselines for 

monitoring CO2 surface leakage. Baseline data represent preinjection site conditions and are used to identify potential 

anomalies in monitoring data.490

A summary of considerations made to calculate site-specific 

variables for the mass balance equation. Site-specific variables 

may include calculating CO2 emissions from equipment leaks and 

vented emissions of CO2 from surface equipment, and 

considerations for calculating CO2 from produced fluids.491

Subpart RR provides a nationally consistent mass balance 

framework for reporting the mass of CO2 that is sequestered. 

Certain monitoring and operational data for a GS site is 

required to be reported to the EPA annually. More information on 

the MRV plan and annual reporting is available in the subpart RR 

final rule (75 FR 75065; December 1, 2010) and its associated 

technical support document.492

Under this final rule, any well receiving CO2 captured from 

an affected EGU, be it a Class VI or Class II well, must report 

under subpart RR.493 As explained below in Section V.N.5.a, a 

 

490 40 CFR §98.448(a)(4).

491 40 CFR §98.448(a)(5).

492 Technical Support Document: “General Technical Support 

Document for Injection and Geologic Sequestration of Carbon 

Dioxide: Subparts RR and UU” (Docket EPA–HQ–OAR–2009–0926), 

November 2010.

493 See §60.5555(f).
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Class II well’s UIC regulatory status does not change because it 

receives such CO2. Nor does it change by virtue of reporting 

under subpart RR.

3. UIC and GHGRP Rules Provide Assurance to Prevent, Monitor, 

and Address Releases of Sequestered CO2 to Air

Together the requirements of the UIC and GHGRP programs 

help ensure that sequestered CO2 will remain secure, and provide 

the monitoring mechanisms to identify and address potential 

leakage using SDWA and CAA authorities. The EPA designed the 

GHGRP subpart RR requirements for GS with consideration of UIC 

requirements. The monitoring required by GHGRP subpart RR is 

complementary to and builds on UIC monitoring and testing 

requirements. 75 FR 77263. Although the regulations for Class VI 

and Class II injection wells are designed to ensure protection 

of USDWs from endangerment the practical effect of these 

complementary technical requirements, as explained below, is 

that they also prevent releases of CO2 to the atmosphere.

The UIC and GHGRP programs are built upon an understanding 

of the mechanisms by which CO2 is retained in geologic 

formations, which are well understood and proven. 

Structural and stratigraphic trapping is a physical 

trapping mechanism that occurs when the CO2 reaches a 

stratigraphic zone with low permeability (i.e., geologic 

confining system) that prevents further upward migration. 
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Residual trapping is a physical trapping mechanism that 

occurs as residual CO2 is immobilized in formation pore spaces as 

disconnected droplets or bubbles at the trailing edge of the 

plume due to capillary forces. 

Adsorption trapping is another physical trapping mechanism 

that occurs when CO2 molecules attach to the surfaces of coal and 

certain organic rich shales, displacing other molecules such as 

methane. 

Solubility trapping is a geochemical trapping mechanism 

where a portion of the CO2 from the pure fluid phase dissolves 

into native ground water and hydrocarbons.

Mineral trapping is a geochemical trapping mechanism that 

occurs when chemical reactions between the dissolved CO2 and 

minerals in the formation lead to the precipitation of solid 

carbonate minerals. 

a. Class VI wells

As just discussed in Section V.N.1, the UIC Class VI rule 

provides a framework to ensure the safety of underground 

injection of CO2 such that USDWs are not endangered. As explained 

below, protection against releases to USDWs likewise assures 

against releases to ambient air. Through the injection well 

permit application process, the Class VI permit applicant (i.e., 

a prospective Class VI well owner or operator) must demonstrate 

that the injected CO2 will be trapped and retained in the 
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geologic formation, and not migrate out of the injection zone or 

the approved project area (i.e., the area of review). To assure 

that CO2 is confined within the injection zone, major components 

to be considered and included in Class VI permits are site 

characterization, area of review delineation and corrective 

action, well construction and operation, testing and monitoring, 

financial responsibility, post-injection site care, well 

plugging, emergency and remedial response, and site closure as 

described in Section V.N.1.

Site characterization provides the foundation for 

successful GS projects. It includes evaluation of the chemical 

and physical mechanisms that will occur in the subsurface to 

immobilize and securely store the CO2 within the injection zone 

over the long-term (see above). Site characterization requires a

detailed assessment of the geologic, hydrogeologic, geochemical, 

and geomechanical properties of the proposed GS site to ensure 

that wells are sited in suitable locations.494 Data and 

information collected during site characterization are used in 

the development of injection well construction and operating 

plans; provide inputs for modeling the extent of the injected CO2

plume and related pressure front; and establish baseline 

information to which geochemical, geophysical, and hydrogeologic 

 

494 40 CFR §146.82(a) and (c).
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site monitoring data collected over the life of the injection 

project can be compared. 

The Class VI rules contain rigorous subsurface monitoring 

requirements to assure that the chosen site is functioning as 

characterized. This subsurface monitoring should detect leakage 

of CO2 before CO2 would reach the atmosphere. For example, when 

USDWs are present, they are generally located above the 

injection zone. If CO2 were to reach a USDW prior to being 

released to the atmosphere, the presence of CO2 or geochemical 

changes that would be caused by CO2 migration into unauthorized 

zones would be detected by a UIC Class VI monitoring program 

that is approved and periodically evaluated/adjusted based on 

permit conditions. 

Likewise, UIC Class VI mechanical integrity testing 

requirements are designed to confirm that a well maintains 

internal and external mechanical integrity. Continuous 

monitoring of the internal mechanical integrity of Class VI

wells ensures that injection wells maintain integrity and serves 

as a way to detect problems with the well system. Mechanical 

integrity testing provides an early indication of potential 

issues that could lead to CO2 leakage from the confining zone, 

providing assurance and verification that CO2 will not reach the 

atmosphere. 
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Further assurance is provided by the regulatory requirement 

that injection must cease if there is evidence that the injected 

CO2 and/or associated pressure front may cause endangerment to a 

USDW.495 Once the anomalous operating conditions are verified, 

the cessation of injection, as required by UIC permits, will 

minimize any risk of release to air.

Following cessation of injection, the operator must conduct 

comprehensive post-injection site care to show the position of 

the CO2 plume and the associated area of elevated pressure to 

demonstrate that neither poses an endangerment to USDWs – also 

having the practical effect of preventing releases of CO2 to the 

atmosphere. Post-injection site care includes appropriate 

monitoring and other needed actions (including corrective 

action). The default duration for the post-injection site care 

period is 50 years, with flexibility for demonstrating that an 

alternative period is appropriate if it ensures non-endangerment 

of USDWs.

As the EPA has found, the UIC Class VI injection well 

requirements protect against releases from all exposure 

pathways. Specifically, the EPA stated that the Class VI rules

“[are] specifically designed to ensure that the CO2 (and any 

incidental associated substances derived from the source 

 

495 40 CFR § 146.94(b).
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materials and the capture process) will be isolated within the 

injection zone. The EPA concluded that the elimination of 

exposure routes through these requirements, which are 

implemented through a SDWA UIC permit, will ensure protection of 

human health and the environment...”.

496

GHGRP subpart RR complements these UIC Class VI 

requirements. Requirements under the UIC program are focused on 

demonstrating that USDWs are not endangered as a result of CO2

injection into the subsurface, while requirements under the 

GHGRP through subpart RR enable accounting for CO2 that is 

geologically sequestered. A methodology to account for potential 

leakage is developed as part of the subpart RR MRV plan (see 

Section V.N.2). The MRV plan submitted for subpart RR may 

describe (or provide by reference to the UIC permit) the 

relevant elements of the UIC permit (e.g. assessment of leakage 

pathways in the monitoring area) and how those elements satisfy 

the subpart RR requirements. The MRV plan required under subpart 

RR may rely upon the knowledge of the subsurface location of CO2

and site characteristics that are developed in the permit 

application process, and operational monitoring results for UIC 

Class VI permitted wells. 

 

496 79 FR at 353 (January 3, 2014) (Final Hazardous Waste 

Management System: Conditional Exclusion for Carbon Dioxide (CO2) 

Streams in Geologic Sequestration Activities under subtitle C of 

RCRA). See Section N.5.c below.
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In summary, there are well-recognized physical mechanisms 

for storing CO2 securely. The comprehensive and rigorous site 

characterization requirements of the Class VI rules assure that 

sites with these properties are selected. Subsurface monitoring 

serves to assure that the sequestration site operates as 

intended, and this monitoring continues through a post-closure 

period. Although release of CO2 to air is unlikely and should be 

detected prior to release by subsurface monitoring, the subpart 

RR air-side monitoring and reporting regime provides backup 

assurance that sequestered CO2 has not been released to the 

atmosphere.

b. Class II wells

The Class II rules likewise are designed to protect USDWs 

during EOR operation, including the injection of CO2 for EOR. For 

example, UIC Class II minimum federal requirements promulgated 

under SDWA address site characterization, area of review, well 

construction (e.g., casing and cementing), well operation (e.g., 

injection pressure), injectate sampling, mechanical integrity 

testing, plugging and abandonment, financial responsibility, and 

reporting. Class II wells must undergo periodic mechanical 

integrity testing which will detect well construction and 

operational conditions that could lead to loss of injectate and

migration into USDWs. The establishment of maximum injection 

pressures, designed to ensure that the pressure in the injection 
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zone during injection does not initiate new fractures or 

propagate existing fractures in the confining zone, prevents 

injection from causing the movement of fluids into an 

underground source of drinking water. The safeguards that 

protect USDWs also serve as an early warning mechanism for 

releases of CO2 to the atmosphere.

CO2 injected via Class II wells becomes sequestered by the

trapping mechanisms described above in this Section V.N.3. As 

with Class VI wells, for Class II wells that report under 

subpart RR, there is monitoring to evaluate whether CO2 used for 

EOR will remain safely in place both during and after the 

injection period. Subpart RR provides a CO2 accounting framework 

that will enable the EPA to assess both the project-level and 

national efficacy of geologic sequestration to determine whether 

additional requirements are necessary and, if so, inform the 

design of such regulations.

c. Response to comments

Commenters maintained that GS was not demonstrated for CO2

captured from EGUs. In addition, commenters noted that the 

volumes of captured CO2 would be considerably larger than from 

existing GS sites, and could quadruple amounts injected into 

Class II EOR wells. In addition to volumes of CO2 to be injected, 
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commenters opined on the possibility of sporadic CO2 supply due 

to the nature of EGU operation.497

The EPA does not agree. CO2 capture from EGUs is 

demonstrated as discussed in Sections V.D and V.E. As discussed 

below, the volumes of CO2 are comparable to the amounts that have 

been injected at large scale commercial operations. The EPA also 

disagrees that the volume of CO2 would quadruple amounts injected 

into Class II EOR wells because CO2 may be sequestered in deep 

saline formations, which have widespread geographic availability 

(see Section M.1). The BSER determination and regulatory impact 

analysis for this rule relies on GS in deep saline formations.

498

However, the EPA also recognizes the potential for sequestering 

CO2 via EOR and allows the use of EOR as a compliance option. 

According to data reported to the GHGRP, approximately 60 

million metric tons of CO2 were supplied to EOR in the United 

States in 2013.499 Approximately 70 percent of total CO2 supplied 

in the United States was produced from geologic (natural) CO2

sources and approximately 30 percent was captured from 

anthropogenic sources. CO2 pipeline systems, such as those 

 

497 See, e.g. Comments of Southern Company, p. 41.

498 The EPA anticipates EOR projects may be early GS projects 

because these formations have been previously well characterized 

for hydrocarbon recovery, likely already have suitable 

infrastructure (e.g., wells, pipelines, etc.), and have an 

associated economic benefit of oil production.

499 Greenhouse Gas Reporting Program, data reported as of August 

18, 2014.
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serving the Permian Basin, have multiple sources of CO2 that 

serve to levelize the pipeline supply, thus minimizing the 

effect of supply on the EOR operator. 

GS of anthropogenic CO2 in deep saline formations is 

demonstrated. First, as explained above, the EPA has issued 

construction permits under the Class VI program. It would not 

have done so, and under the regulations cannot have done so, 

without demonstrations that CO2 would be securely confined. One 

of these projects was for a steam generating EGU. 

Second, international experience with large scale 

commercial GS projects has demonstrated through extensive 

monitoring programs that large volumes of CO2 can be safely 

injected and securely sequestered for long periods of time at 

volumes and rates consistent with those expected under this 

rule. This experience has also demonstrated the value and 

efficacy of monitoring programs to determine the location of CO2

in the subsurface and detect potential leakage through the 

presence of CO2 in the shallow subsurface, near surface and air. 

The Sleipner CO2 Storage Project is located at an offshore 

gas field in the North Sea where CO2 must be removed from the 

natural gas in order to meet customer requirements and reduce 

costs. The project began injecting CO2 into the deep subsurface 

in 1996. The single offshore injection well injects 

approximately 1 million metric tons per year into a thick, 
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permeable sandstone above the gas producing zone. Approximately 

15 million metric tons of CO2 have been injected since inception. 

Many US and international organizations have conducted 

monitoring at Sleipner. The location and dimensions of the CO2

plume have been measured numerous times using 3-dimensional 

seismic monitoring since the 1994 pre-injection survey. The 

monitoring data have demonstrated that although the plume is 

behaving differently than initially modeled due to thin layers 

of impermeable shale that were not initially identified in the 

reservoir model, the CO2 remains trapped in the injection zone. 

Numerous other techniques have been successfully used to monitor 

CO2 storage at Sleipner. The research and monitoring at Sleipner 

demonstrates the value of a comprehensive approach to site 

characterization, computational modeling and monitoring, as is 

required under UIC Class VI rules. The experience at Sleipner 

demonstrates that large volumes of CO2, of the same order of 

magnitude expected for an EGU, can be safely injected and stored 

in saline reservoirs over an extended period.

Snøhvit is another large offshore CO2 storage project, 

located at a gas field in the Barents Sea. Like Sleipner the 

natural gas must be treated to reduce high levels of CO2 to meet 

processing standards and reduce costs. Gas is transported via 

pipeline 95 miles to a gas processing and liquefied natural gas 

plant and the CO2 is piped back offshore for injection. 
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Approximately 0.7 million metric tons per year CO2 are injected 

into permeable sandstone below the gas reservoir. Between 2008 

and 2011, the operator observed pressure increases in the 

injection formation (Tubaen Formation) greater than expected and 

conducted time lapse seismic surveys and studies of the 

injection zone and concluded that the pressure increase was 

mainly caused by a limited storage capacity in the formation.500

In 2011, the injection well was modified and injection was 

initiated in a second interval (Stø Formation) in the field to 

increase the storage capacity. Approximately 3 million metric 

tons of CO2 have been injected since 2008. Monitoring 

demonstrates that no leakage has occurred, again demonstrating

that large volumes of CO2, of the same order of magnitude 

expected for an EGU, can be safely injected and stored in deep 

saline formations over an extended period.

As discussed above in Sections V.E.2.a and M, CO2 from the 

Great Plains Synfuels plant in North Dakota has been injected 

into the Weyburn oil field in Saskatchewan Canada since 2000. 

Over that time period the project has injected more than 16 

 

500 Grude, S. M. Landrøa, and J. Dvorkinb, 2014, Pressure effects

caused by CO2 injection in the Tubåen Fm., the Snøhvit field. 

International Journal of Greenhouse Gas Control 27 (2014) 178–

187. Commenters argued that the project had failed to sequester 

CO2, referring to the initial cessation of injection. See, e.g. 

Comments of UARG p. 56. In fact, injection resumed successfully, 

as described in the text above.
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million metric tons of CO2. It is anticipated that approximately 

40 million metric tons of CO2 will be permanently sequestered 

over the lifespan of the project. Extensive monitoring by U.S.

and international partners has demonstrated that no leakage has 

occurred. The sources of CO2 for EOR may vary (e.g., industrial 

processes, power generation); however, this does not impact the 

effectiveness of EOR operations (see Section V.M.3). 

CO2 used for EOR may come from anthropogenic or natural 

sources. The source of the CO2 does not impact the effectiveness 

of the EOR operation. CO2 capture, treatment and processing steps 

provide a concentrated stream of CO2 in order to meet the needs 

of the intended end use. CO2 pipeline specifications of the U.S. 

Department of Transportation Pipeline Hazardous Materials Safety 

Administration found at 49 CFR part 195 (Transportation of 

Hazardous Liquids by Pipeline) apply regardless of the source of 

the CO2 and take into account CO2 composition, impurities, and 

phase behavior. Additionally, EOR operators and transport 

companies have specifications to ensure related to the 

composition of CO2. These requirements and specifications ensure 

EOR operators receive a known and consistent CO2 stream.

At the In Salah CO2 storage project in Algeria, CO2 is 

removed from natural gas produced at three nearby gas fields in 

order to meet export quality specification. The CO2 is 

transported by pipeline approximately 3 miles to the injection 
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site. Three horizontal wells are used to inject the CO2 into the 

down-dip aquifer leg of the gas reservoir approximately 6,200 

feet deep. Between 2004 and 2011 over 3.8 million metric tons of 

CO2 were stored. Injection rates in 2010 and 2011 were 

approximately 1 million metric tons per year. Storage integrity 

has been monitored by several US and international organizations 

and the monitoring program has employed a wide range of 

geophysical and geochemical methods, including time lapse 

seismic, microseismic, wellhead sampling, tracers, down-hole 

logging, core analysis, surface gas monitoring, groundwater 

aquifer monitoring and satellite data. The data have been used 

to support periodic risk assessments during the operational 

phase of the project. In 2010 new data from seismic, satellite 

and geomechanical models were used to inform the risk assessment 

and led to the decision to reduce CO2 injection pressures due to 

risk of vertical leakage into the lower caprock, and risk of 

loss of well integrity. The caprock at the site consisted of 

main caprock units, providing the primary seal, and lower 

caprock units, providing additional buffers. There was no 

leakage from the well or through the caprock, but the risk 

analysis identified an increased risk of leakage, therefore, the 

aforementioned precautions were taken. Additional analysis of

the reservoir, seismic and geomechanical data led to the 

decision to suspend CO2 injection in June 2011. No leakage has 
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occurred and the injected CO2 remains safely stored in the 

subsurface. The decision to proceed with safe shutdown of 

injection resulted from the analysis of seismic and 

geomechanical data to identify and respond to storage site risk. 

The In Salah project demonstrates the value of developing an 

integrated and comprehensive set of baseline site data prior to 

the start of injection, and the importance of regular review of 

monitoring data. Commenters also noted that the data collection 

and analysis had proven effective at preventing any release of 

sequestered CO2 to either underground drinking water sources or 

to the atmosphere.

501

These projects demonstrate that sequestration of CO2

captured from industrial operations has been successfully 

conducted on a large scale and over relatively long periods of 

time. The volumes of captured CO2 are within the same order of 

magnitude as that expected from EGUs. Even though potentially 

adverse conditions were identified at some projects (In Salah 

and Snøhvit), there were no releases to air and the monitoring 

systems were effective in identifying the issues in a timely 

 

501 “It is important to note that although the In Salah project 

is no longer injecting CO2, the CCS community still views this 

early saline project as a success because the monitoring program 

served its intended purpose. That is, the monitoring methods 

deployed at this site informed the operator of a potential 

problem, leading to a shutdown of CO2 injection before the 

Caprock was breached.” Comment of EPRI, p. 14.
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manner, and these issues were addressed effectively. In each 

case, the site-specific characteristics were evaluated on a 

case-by-case basis to select a site where the geologic 

conditions are suitable to ensure long-term, safe storage of CO2. 

Each project was designed to address the site-specific 

characteristics and operated to successfully inject CO2 for safe 

storage.

4. Must the standard of performance for CO2 include CAA

requirements on the sequestration site? 

One commenter maintained as a matter of law that a standard 

predicated on use of CCS is not a “system of emission 

reduction”, and therefore is not a “standard of performance” 

within the meaning of section 111 (a)(1) of the Act. The 

commenter argued that the standard does not require

sequestration of captured CO2 but only capture, so that no 

emission reductions are associated with the standard. A gloss on 

this argument is that there are no enforceable requirements for 

the captured CO2 (“[t]he fate of that [captured] CO2 is something 

that the proposed standard does not proscribe with enforceable 

requirements”). The commenter further argues that a “system of 

emission reduction” under section 111 must be “designed into the 

new source itself” so that off-site underground sequestration of 

captured CO2 emissions “could never satisfy the statutory 
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requirements governing a ‘standard of performance’” (emphasis 

original).502

The EPA disagrees with both the legal and factual

assertions in this comment. As to the legal point, the commenter 

fails to distinguish capture and sequestration of carbon from 

every other section 111 standard which is predicated on capture 

of a pollutant. Indeed, all emission standards not predicated on 

outright pollutant destruction involve capture of the pollutant 

and its subsequent disposition in the capturing medium. Thus, 

metals are captured in devices like baghouses or scrubbers, 

leaving a solid waste or wastewater to be managed. Gases can be 

captured with activated carbon or under pressure, again 

requiring further management of the captured pollutant(s). The 

EPA is required to consider these potential implications in 

promulgating an NSPS. See section 111(a)(1) (in promulgating a 

standard of performance under section 111, the EPA must “tak[e] 

into account ... any nonair quality health and environmental 

impact”). The EPA thus considers such issues as solid waste and 

wastewater generation as part of determining if a system of 

emission reduction is “best” and “adequately demonstrated” under 

section 111. See Section V.O below (discussion of this rule’s 

potential cross-media impacts).

 

502 Comments of UARG, pp. 37-38.
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The further comment that the standard is arbitrary because 

it fails to impose any requirements on the captured CO2 is 

misplaced. The commenter mischaracterizes the standard as 

requiring capture only. The BSER is not just capturing a certain 

amount of CO2, but sequestering it. Sequestration can occur 

either on-site or off-site. Sequestration sites receiving and 

injecting the captured CO2 are required to obtain UIC permits and

report under subpart RR of the GHGRP. They must conduct 

comprehensive monitoring as part of these obligations. Although 

the NSPS does not impose regulatory requirements on the 

transportation pipeline or the sequestration site, such 

requirements already exist under other regulatory programs of 

the Department of Transportation and the EPA. In particular, the 

EPA is reasonably relying on the already-adopted, and very 

rigorous, Class VI well requirements in combination with the 

subpart RR requirements to provide secure sequestration of

captured CO2. The EPA has also considered carefully the 

requirements and operating history of the Class II requirements 

for EOR wells, which, in combination with the subpart RR 

requirements, ensure protection of USDWs from endangerment,

provide the monitoring mechanisms to identify and address 

potential leakage using SDWA and CAA authorities, and have the 

practical effect of preventing releases of CO2 to the atmosphere. 

This is analogous to the many section 111 standards of 
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performance for metals which result in a captured air pollution 

control residue to be disposed of pursuant to waste management 

requirements of the rules implementing the Resource Conservation 

and Recovery Act. It is also analogous to the many section 111 

standards of performance for metals or organics captured in wet 

air pollution control systems resulting in wastewater discharged 

to a navigable water where pollutant loadings are controlled 

under rules implementing the Clean Water Act. Again, these are 

non-air environmental impacts for which the EPA must account in 

establishing a section 111(a) standard. The EPA has reasonably 

done so here based on the regulatory regimes of the Class VI and 

Class II UIC requirements in combination with the monitoring 

regime of the subpart RR reporting rules, as well as the CO2

pipeline standards of the Department of Transportation. 

In this regard, the EPA notes that at proposal it 

acknowledged the possibility “that there can be downstream 

losses of CO2 after capture, for example during transportation, 

injection or storage.” 79 FR at 1484. Given the rigorous 

substantive requirements and the monitoring required by the 

Class VI rules, the complementary monitoring regime of the 

subpart RR MRV plan and reporting rules, as well as the 

regulatory requirements for Class II wells, any such losses 

would be de minimis. Indeed, the same commenter maintained that 

the monitoring requirements of the Class VI rule are overly 
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stringent and that a 50-year post-injection site care period is 

unnecessarily long.503 As it happens, as noted above, the Class 

VI rules allow for an alternative post-injection site care 

period based on a site-specific demonstration. See 40 CFR 

146.93(b).

The EPA addresses this comment in more detail in Chapter 2 

of the Response-to-Comment Document.

5. Other Perceived Obstacles to Geologic Sequestration

a. Class II to Class VI transition

A number of commenters maintained that the Class VI rules 

could effectively force all Class II wells to transition to 

Class VI wells if they inject anthropogenic CO2, and further 

maintained that, as a practical matter, this would render EOR 

unavailable for such CO2. The EPA disagrees with these comments. 

Injection of anthropogenic CO2 into Class II wells does not force 

transition of these wells to Class VI wells – not during the 

well’s active operation and not when EOR operations cease. We 

recognize the widespread use of EOR and the expectation that 

injected CO2 can remain underground. The EPA issued a memorandum 

to its regional offices on April 23, 2015 reflecting these 

principles:504

 

503 Comments of UARG, p. 63.

504 “Key Principles in EPA’s Underground Injection Control 

Program Class VI Rule Related to Transition of Class II Enhanced 
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Geologic storage of CO2 can continue to be permitted under 

the UIC Class II program. 

Use of anthropogenic CO2 in EOR operations does not 

necessitate a Class VI permit. 

Class VI site closure requirements are not required for 

Class II CO2 injection operations. 

EOR operations that are focused on oil or gas production 

will be managed under the Class II program. If oil or gas 

recovery is no longer a significant aspect of a Class II 

permitted EOR operation, the key factor in determining the 

potential need to transition an EOR operation from Class II to 

Class VI is increased risk to USDWs related to significant 

storage of CO2 in the reservoir, where the regulatory tools of 

the Class II program cannot successfully manage the risk.505

b. GHGRP Subpart RR

A number of commenters maintained that no EOR operator 

would accept captured carbon from an EGU due to the reporting 

and other regulatory burdens imposed by the monitoring 

 

Oil Recovery or Gas Recovery Wells to Class VI”, April 23, 2015. 

Available at: 

http://water.epa.gov/type/groundwater/uic/class6/upload/class2eo

rclass6memo.pdf.

505 In this regard, the Class VI rules provide that, “[o]wners or 

operators that are injecting carbon dioxide for the primary 

purpose of long-term storage into an oil and gas reservoir must 

apply for and obtain a Class VI geologic sequestration permit 

when there is an increased risk to USDWs compared to Class II 

operations.” 40 CFR §144.19. 
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requirements of GHGRP subpart RR.506 They noted that preparing a

subpart RR MRV plan could cost upwards of $100,000 which would 

be cost prohibitive given other available sources of CO2.

The EPA disagrees with this comment in several respects. 

First, the BSER determination and regulatory impact analysis for 

this rule relies on GS in deep saline formations, not on EOR. 

However, the EPA also recognizes the potential for sequestering 

CO2 via EOR, but disagrees that subpart RR requirements 

effectively preclude or substantially inhibit the use of EOR. 

The cost of compliance with subpart RR is not significant 

enough to offset the potential revenue for the EOR operator from 

the sale of produced oil for CCS projects that are reliant on 

EOR. First, the costs associated with subpart RR are relatively 

modest, especially in comparison with revenues from an EOR 

field. In the economic impact analysis for subpart RR, the EPA 

estimated that an EOR project with a Class II permit would incur 

a first year cost of up to $147,030 to develop an MRV plan, and 

an annual cost of $27,787 to maintain the plan; the EPA 

estimated annual reporting and recordkeeping costs at $13,262 

per year.507 Monitoring costs are estimated to range from $0.02 

per metric ton (base case scenario) to approximately $2 per 

 

506 See e.g., comments of UARG, p, 63; Southern Co., p. 37; 

American Petroleum Institute pp. 40-50.

507 Subpart RR costs are presented in 2008 US dollars.
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metric ton of CO2 (high scenario). Using a range of scenarios 

(that included high end estimates), these subpart RR costs are 

approximately three to four percent of estimated revenues for an 

average EOR field, indicating that the costs can readily be 

absorbed. 75 FR 75073.

Furthermore, there is a demand for new CO2 by EOR operators, 

even beyond current natural sources of CO2. For example, in an 

April 2014 study, DOE concluded that future development of EOR 

will need to rely on captured CO2.

508 Thus, the argument that EOR 

operators will obtain CO2 from other sources without triggering 

subpart RR responsibilities, which assumes adequate supplies of 

CO2 from other sources, lacks foundation. In addition, the 

Internal Revenue Code section 45Q provides a tax credit for CO2

sequestration which is far greater than subpart RR costs.

509 In 

sum, the cost of complying with subpart RR requirements, 

including the cost of MRV, is not significant enough to deter 

EOR operators from purchasing EGU captured CO2.

The EPA addresses these comments in more detail in the 

Response to Comment Document. 

 

508 “Near Term Projections of CO2 Utilization for Enhanced Oil 

Recovery”. DOE/NETL-2014/1648. April 2014. 

509 http://www.irs.gov/irb/2009-44_IRB/ar11.html. The section 45Q 

tax credit for calendar year 2015 is $10.92 per metric ton of 

qualified CO2 that is captured and used in a qualified EOR 

project and $21.85 per metric ton of qualified CO2 that is 

captured and used in a qualified non-EOR GS project. 

http://www.irs.gov/irb/2015-26_IRB/ar14.html. 
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c. Conditional exclusion for geologic sequestration of CO2

streams under the Resource Conservation and Recovery Act (RCRA)

Certain commenters voiced concerns that regulatory 

requirements for hazardous wastes might apply to captured CO2 and 

these requirements might be inconsistent with, or otherwise 

impede, GS of captured CO2 from EGUs. The EPA has acted to remove 

any such (highly conjectural) uncertainty. The Resource 

Conservation and Recovery Act (RCRA) authorizes the EPA to 

regulate the management of hazardous wastes. In particular, RCRA 

Subtitle C authorizes a cradle to grave regulatory program for 

wastes identified as hazardous, whether specifically listed as 

hazardous or whether the waste fails certain tests of hazardous 

characteristics. The EPA currently has little information to 

conclude that CO2 streams (defined in the RCRA exclusion rule as 

including incidental associated substances derived from the 

source materials and the capture process, and any substances 

added to the stream to enable or improve the injection process) 

might be identified as “hazardous wastes” subject to RCRA 

Subtitle C regulation.510 Nevertheless, to reduce potential 

uncertainty regarding the regulatory status of CO2 streams under 

RCRA Subtitle C, and in order to facilitate the deployment of 

 

510 No hazardous waste listings apply to CO2 streams. Therefore, a 

CO2 stream could be identified (i.e. defined) as a hazardous 

waste only if it exhibits one or more of the hazardous 

characteristics. 79 FR 355 (Jan 3. 2014).
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geologic sequestration, the EPA recently concluded a rulemaking 

to exclude certain CO2 streams from the RCRA definition of 

hazardous waste.511 In that rulemaking, the EPA determined that 

if any such CO2 streams would be hazardous wastes, further RCRA 

regulation is unnecessary to protect human health and the 

environment provided certain conditions are met. Specifically, 

the rule conditionally excludes from Subtitle C regulations CO2

streams if they are (1) transported in compliance with U.S. 

Department of Transportation or state requirements; (2) injected 

in compliance with UIC Class VI requirements (summarized above); 

(3) no other hazardous wastes are mixed with or co-injected with 

the CO2 stream; and (4) generators (e.g., emission sources) and 

Class VI well owners or operators sign certification statements. 

See 40 CFR 261.4(h)).512 The D.C. Circuit recently dismissed all 

 

511 79 FR 350 (Jan. 3, 2014).

512 The EPA made clear in the final conditional exclusion that 

that rule does not address, and is not intended to affect the 

RCRA regulatory status of CO2 streams that are injected into 

wells other than Class VI. However, the EPA noted in the 

preamble to the final rule that (based on the limited 

information provided in public comments) should CO2 be used for 

its intended purpose as it is injected into UIC Class II wells 

for the purpose of EOR/EGR (enhanced oil recovery / enhanced gas 

recovery), it is the EPA’s expectation that such an injection 

process would not generally be a waste management activity. 79 

FR 355. The EPA encouraged persons to consult with the 

appropriate regulatory authority to address any fact-specific 

questions that they may have regarding the status of CO2 in 

situations that are beyond the scope of that rule. Id. Moreover, 

use of anthropogenic CO2 for EOR is long-standing and has 

flourished in all of the years that EPA’s subtitle C regulations 
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challenges to this rule in Carbon Sequestration Council and 

Southern Company Services v. EPA, No. 787 F. 3d 1129 (D.C Cir. 

2015).

d. Other perceived uncertainties

Other commenters claimed that various legal uncertainties 

preclude a finding that geologic sequestration of CO2 from EGUs 

can be considered to be adequately demonstrated. Many of the 

issues referred to in comments relate to property rights: issues 

of ownership of pore space, relationship of sequestration to 

ownership of mineral rights, issues of dealing with multiple 

landowners, lack of state law frameworks, or competing, 

inconsistent state laws.513 Other commenters noted the lack of 

long-term liability insurance, and noted uncertainties regarding 

long-term liability generally.

514

An IPCC special report on CCS found that with an 

appropriate site selection, a monitoring program, a regulatory 

system, and the appropriate use of remediation methods, the 

risks of GS would be comparable to risks of current activities, 

such as EOR, acid gas injection and underground natural gas

 

(which among other things, define what a solid waste is for 

purposes of those regulations) have been in place. The RCRA 

subtitle C regulatory program consequently has not been an

impediment to use of anthropogenic CO2 for EOR.

513 See e.g. Comments of Duke Energy, p. 28; UARG, p. 62; AEP, p. 

91.

514 See e.g. Comments of UARG, pp. 26, 62; EEI, p. 92; Duke 

Energy, pp. 27, 28.
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storage.

515 Furthermore, an interagency CCS task force examined 

GS-related legal issues thoroughly and concluded that early CCS 

projects can proceed under the existing legal framework with 

respect to issues such as property rights and liability.516 As 

noted earlier, both the Archer Daniels Midland (ADM) and 

FutureGen projects addressed siting and operational aspects of 

GS (including issues relating to volumes of the CO2 and the

nature of the CO2 injectate) in their permit applications. The 

fact that these applicants pursued permits indicates that they 

regarded any potential property rights issues as resolvable. 

Commenter American Electric Power (AEP) referred to its own 

experience with the Mountaineer demonstration project. AEP noted 

that although this project was not full scale, finding a 

suitable repository, notwithstanding a generally favorable 

geologic area, proved difficult. The company referred to years 

spent in site characterization and digging multiple wells.517

Other commenters noted more generally that site characterization 

issues can be time-consuming and difficult, and quoted studies 

 

515 Intergovernmental Panel on Climate Change. (2005). Special 

Report on Carbon Dioxide Capture and Storage.

516 http://www.epa.gov/climatechange/Downloads/ccs/CCS-TaskForce-Report-2010.pdf.

517 AEP Comments at pp. 93, 96. 
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suggesting that it could take 5 years to obtain a Class VI 

permit.518

The EPA agrees that robust site characterization and 

selection is important to ensuring capacity needs are met and 

that the sequestered CO2 is safely stored. Efforts to 

characterize geologic formations suitable for GS have been 

underway at DOE through the RCSPs since 2003 (see Section V.M). 

Additionally, since 2007, the USGS has been assessing U.S.

geologic storage resources for CO2. As noted earlier, DOE, in 

partnership with researchers, universities, and organizations 

across the country, is demonstrating that GS can be achieved 

safely, permanently, and economically at large scales, and 

projects supported by the department have safely and permanently 

stored 10 million metric tons of CO2. 

In the time since the commenter submitted comments several 

Class VI permits have been issued by the EPA. These projects 

demonstrate that a GS site permit applicant could potentially

prepare and obtain a UIC permit concurrent with permits required

for an EGU. With respect to AEP’s experience with the 

Mountaineer demonstration project, notwithstanding difficulties, 

the company was able to successfully dig wells, and safely 

inject captured CO2. Moreover, the company indicated it fully 

 

518 See e.g. Comments of UARG, p. 55, citing to Cichanowitz CCS 

Report (2012).
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expected to be able to do so at full scale and explained how.519

The EPA notes further that a monitoring program and its 

associated infrastructure (e.g., monitoring wells) and costs 

will be dependent on site-specific characteristics, such as CO2

injection rate and volume, geology, the presence of artificial 

penetrations, among other factors. It is thus not appropriate to 

generalize from AEP’s experience, and assume that other sites 

will require the same number of wells for site characterization 

or injection. In this regard, we note that the ADM and FutureGen 

construction permits for Class VI wells involved far fewer 

injection wells than AEP references.520 See also discussion of 

this issue in Section V.I.5 above.

O. Non-air Quality Impacts and Energy Requirements

As part of the determination that SCPC with partial CCS is 

the best system of emission reduction adequately demonstrated, 

the EPA has given careful consideration to non-air quality 

 

519 See AEP FEED Study at pp. 36-43. The company likewise 

explained the monitoring regime it would utilize to verify 

containment, and the well construction it would utilize to 

guarantee secure sequestration. Id. at pp. 44-54. Available at: 

www.globalccsinstitute.com/publications/aep-mountaineer-iiproject-front-end-engineering-and-design-feed-report.

520 The FutureGen UIC Class VI injection well permits (four in 

total) require nine monitoring wells. 

http://www.epa.gov/r5water/uic/futuregen/. The Archer Daniels 

Midland UIC Class VI injection well permit issued in September 

2014 (CCS2) requires five monitoring wells and the Archer 

Daniels Midland UIC Class VI injection well permit issued in 

December 2014 (CCS1) was permitted with two monitoring wells. 

http://www.epa.gov/region5/water/uic/adm/.
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health and environmental impacts and energy requirements, as 

required by CAA section 111 (a). We have also considered those 

factors for alternative potential compliance paths to assure 

that the standard does not have unintended adverse health, 

environmental or energy-related consequences. The EPA finds that 

neither the BSER, nor the possible alternative compliance 

pathways, would have adverse consequences from either a non-air 

quality impact or energy requirement perspective.

1. Transport and Sequestration of Captured CO2

As just discussed in detail, the EPA finds that the Class 

VI and II rules, as complemented by the subpart RR GHGRP 

reporting and monitoring requirements, amply safeguard against 

potential of injected CO2 to degrade underground sources of 

drinking water and amply protect against any releases of 

sequestered CO2 to the atmosphere. The EPA likewise finds that 

the plenary regulatory controls on CO2 pipelines assure that CO2

can be safely conveyed without environmental release, and that 

these rules, plus the complementary tracking and reporting rules 

in subpart RR, assure that captured CO2 will be properly tracked 

and conveyed to a sequestration site. 

2. Water Use Impacts

Commenters claimed that the EPA ignored the negative 

environmental impacts of the use of CCS for the mitigation of CO2

emissions from fossil fuel-fired steam generating EGUs. In 
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particular, commenters noted that the use of CCS will increase 

the water usage at units that implement CCS to meet the proposed 

standard of performance. At least one commenter claimed that 

addition of an amine-based CCS system would double the 

consumptive water use of a power plant, which would be 

unacceptable, especially in drought-ridden states and in the 

arid west and referenced a study in the scientific literature as 

support.521 The commenter also references a DOE/NETL report that 

likewise notes significant increases in the amount of cooling 

and process water required with the use of carbon capture 

technology.522 However, those studies discuss increased water use 

for cases where full CCS (90 percent or greater capture) is 

implemented. As we discussed in both the proposal and in this 

preamble, the EPA does not find that highly efficient new 

generation technology implementing full CCS is the BSER for new 

steam generating EGUs. 

The EPA examined water use predicted from the updated 

DOE/NETL studies in order to determine the magnitude of 

increased water usage for a new SCPC implementing partial CCS to 

 

521 See comments of UARG at p. 84 referencing Haibo Zhai, et al., 

Water Use at Pulverized Coal Power Plants with Post-combustion 

Carbon Capture and Storage, 45 Environ. Sci. Technol., 2479-85 

(2011).

522 Id at p. 84 referencing DOE/NETL-402/080108, “Water 

Requirements for Existing and Emerging Thermoelectric Plant 

Technologies” at 13 (Aug. 2008, Apr. 2009 revision).
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meet the final standard of 1,400 lb CO2/MWh-g. The predicted 

water consumption for varying levels of partial and full CCS are 

provided in Table 13. The results show that a new SCPC unit that 

implements 16 percent partial CCS to meet the final standard 

would see an increase in water consumption (the difference 

between the predicted water withdraw and discharge) of about 6.4 

percent compared to an SCPC with no CCS and the same net power 

output. By comparison, a unit implementing 35 percent CCS to 

meet the proposed emission limitation of 1,100 lb CO2/MWh-g would 

see an increase in water consumption of 16.0 percent and a new 

unit implementing full (90 percent) CCS would see an increase of 

almost 50 percent.

Table 13. Predicted Water Consumption with Implementation of 

Various Levels of Partial CCS523

Raw Water Increase Compared

Technology Consumption, gpm to SCPC, %

SCPC 4,095 -

SCPC + 16% CCS 4,359 6.4

SCPC + 35% CCS 4,751 16.0

SCPC + 90% CCS 6,069 48.2

IGCC* 3,334 -18.6

IGCC + 90% CCS* 4,815 17.6

* The IGCC results presented in the DOE/NETL report are for an 

IGCC with net output of 622 MWe and an IGCC with full CCS with 

net output of 543 MWe. The water consumption for each was 

normalized to 550 MWe to be consistent with the SPCP cases.

 

523 Exhibits A-1 and A-2 at p. 16-17 from “Cost and Performance 

Baseline for Fossil Energy Plants Supplement: Sensitivity to CO2

Capture Rate in Coal-Fired Power Plants”, DOE/NETL-2015/1720 

(June 22, 2015).
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Similar to other air pollution controls – such as a wet 

flue gas desulfurization scrubber – utilization of postcombustion amine-based capture systems results in increased 

consumption of water. However, by finalizing a standard that is 

less stringent than the proposed limitation and by rejecting 

full CCS as the BSER, the EPA has reduced the increased amount 

of water needed as compared to a similar unit without CCS. 

Further, the EPA notes that there are additional opportunities 

to minimize the water usage at such a facility. For example, the 

SaskPower Boundary Dam Unit #3 post-combustion capture project 

captures water from the coal and from the combustion process and 

recycles the captured water in the process, resulting in 

decreased need for withdrawal of fresh water.

The EPA also examined the predicted water usage for a new 

IGCC and for a new IGCC implementing 90 percent CCS. The 

predicted water consumption for the new IGCC unit is nearly 20 

percent less than that predicted for the new SCPC unit without 

CCS (and almost 25 percent less than the SCPC unit meeting the 

final standard). The EPA rejected new IGCC implementing full CCS 

as BSER because the predicted costs were significantly more than 

alternative technologies. The EPA also does not find that a new 

IGCC EGU is part of the final BSER (for reasons discussed in 

Section V.P). However, the EPA does note that IGCC is a viable 
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alternative compliance option and, as shown here, would result 

in less water consumption than a compliant SCPC EGU. The EPA 

also notes that predicted water consumption at a new NGCC unit 

would be less than half that for a new SCPC EGU with the same 

net output.524

3. Energy Requirements

The EPA also examined the expected impacts on energy 

requirements for a new unit meeting the final promulgated 

standard and finds impacts to be minimal. Specifically, the EPA 

examined the increased auxiliary load or parasitic energy 

requirements of a system implementing CCS. The EPA examined the 

predicted auxiliary power demand from the updated DOE/NETL 

studies in order to determine the increased energy requirement 

for a new SCPC implementing partial CCS to meet the final 

standard of 1,400 lb CO2/MWh-g. The predicted gross power output, 

the auxiliary power demand, and the parasitic power demand 

(percent of gross output) are provided in Table 14 for varying 

levels of partial and full CCS. 

Table 14. Predicted Parasitic Power Demand with 

Implementation of Various Levels of Partial CCS525

 

524 The EPA also finds that the standards would not result in any 

significant impact on solid waste generation or management. See 

Section XIII.D below.

525 Exhibits A-1 and A-2 at p. 16-17 from “Cost and Performance 

Baseline for Fossil Energy Plants Supplement: Sensitivity to CO2
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Generation Gross Power Auxiliary

Parasi

tic

Technology Output, MWe Power, MWe

Demand 

(%)

SCPC 580 30 5.2

SCPC + 16% 

CCS 599 38 6.3

SCPC + 35% 

CCS 603 53 8.8

SCPC + 90% 

CCS 642 91 14.2

IGCC 748 126 16.8

IGCC + 90% 

CCS 734 191 26.0

The auxiliary power demand is the amount of the gross power 

output that is utilized within the facility rather than used to 

produce electricity for sale to the grid. The parasitic power 

demand (or parasitic load) is the percentage of the gross power 

 

Capture Rate in Coal-Fired Power Plants”, DOE/NETL-2015/1720 

(June 2015).
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output that is needed to meet the auxiliary power demand.526 In 

an SCPC EGU without CCS, the auxiliary power is used to 

primarily to operate fans, motors, pumps, etc. associated with 

operation of the facility and the associated pollution control 

equipment. When carbon capture equipment is incorporated, 

additional power is needed to operate associated equipment, and 

steam is need to regenerate the capture solvents (i.e., the 

solvents are heated to release the captured CO2).

The results in Table 14 show that a new SCPC unit without 

CCS can expect a parasitic power demand of about 5.2 percent. A 

new SCPC unit meeting the final standard of performance by 

implementing 16 percent partial CCS will see a parasitic power 

demand of about 6.3 percent, which is not a significant increase 

in energy requirement. Of course, new SCPC EGUs that implement 

higher levels of CCS will expect higher amounts of parasitic 

power demand. As shown in Table 14, a new SCPC EGU implementing 

full CCS would expect to utilize over 14 percent of its gross 

power output to operate the facility and the carbon capture 

system. But, the EPA does not find that a new SCPC implementing 

full CCS is the BSER for new fossil-fired steam generating 

units. See Section V.P.2 below.

 

526 Note that this auxiliary power demand is not necessarily met 

from power or steam generated from the EGU. External sources can 

also be utilized for this purposes.
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The EPA also notes that there is on-going research 

sponsored by DOE/NETL and others to further reduce the energy 

requirements of the carbon capture systems. Progress is being 

made. As was mentioned previously, the heat duty (the energy 

required to regenerate the capture solvent) for the amine 

scrubbing process used at the Searles Valley facility in the 

mid-70’s was about 12 MJ/mt CO2 removed as compared to a heat 

duty of about 2.5 MJ/mt CO2 removed for the amine processes used 

at Boundary Dam and for the amine system that will be used at 

the WA Parish facility.527

The EPA also examined the predicted parasitic power demand 

for a new IGCC and for a new IGCC implementing 90 percent CCS. 

As we have noted elsewhere, the auxiliary power demand for a new 

IGCC unit is more than that for that of a new SCPC. As one can 

see in Table 14, a new IGCC unit can expect to see a nearly 17 

percent parasitic power demand; and a new IGCC unit 

implementing full CCS would expect a parasitic power demand of 

nearly 30 percent. Of course, the EPA rejected new IGCC 

implementing full CCS as BSER because of the potentially 

unreasonable costs. The EPA also does not find that a new IGCC 

EGU is part of the final BSER (for reasons discussed elsewhere

 

527 “From Lubbock, TX to Thompsons, TX - Amine Scrubbing for 

Commercial CO2 Capture from Power Plants”, plenary address by 

Prof. Gary Rochelle at the 12th International Conference on 

Greenhouse Gas Technology (GHGT-12), Austin, TX (October 2014).
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in Section V.P.1 below). However, as we have noted, the EPA does 

find IGCC to be a viable alternative compliance option. 

Utilities and project developers should consider the increased 

auxiliary power demand for an IGCC when considering their 

options for new power generation. The EPA also notes that the 

predicted parasitic load for a new NGCC unit would be about 2 

percent - less than half that for a new SCPC EGU with the same 

net output.528

With respect to potential nationwide impacts on energy 

requirements, as described above in Section V.H.3 and more 

extensively in the RIA chapter 4, the EPA reasonably projects 

that no new non-compliant fossil-fuel fired steam electric 

capacity will be constructed through 2022 (the end of the 8 year 

review cycle for NSPS). It is possible, as described earlier, 

that some new sources could be built to preserve fuel diversity, 

but even so, the number of such sources would be small and 

therefore would not significantly impact national energy 

requirements (assuming that such sources would not already be 

reflected in the baseline conditions just noted). 

 

528 The EPA also finds that the standards would not result in any 

significant impact on solid waste generation or management. See 

Section XII.D below.
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P. Options That Were Considered by the EPA but Were Ultimately 

Not Determined to Be the BSER

In light of the comments received, the EPA re-examined 

several alternative systems of emission reduction and reaffirms 

in this rulemaking our proposed determination that those 

alternatives do not represent the “best” system of emission 

reduction when compared against the other available emission 

reduction options. These are described below. See also Section 

IV.B.1 above.

1. Highly Efficient Generation Technology (e.g., Supercritical 

or Ultra-supercritical Boilers)

In the January 2014 proposal, we considered whether ‘Highly 

Efficient New Generation without CCS Technology’ should 

constitute the BSER for new steam generating units. 79 FR at 

1468-69. The discussion focused on the performance of highly 

efficient generation technology (that does not include any 

implementation of CCS), such as a supercritical529 pulverized 

coal (SCPC) or a supercritical CFB boiler, or a modern, wellperforming IGCC unit.

 

529 Subcritical coal-fired boilers are designed and operated with 

a steam cycle below the critical point of water. Supercritical 

coal-fired boilers are designed and operated with a steam cycle 

above the critical point of water. Increasing the steam pressure 

and temperature increases the amount of energy within the steam, 

so that more energy can be extracted by the steam turbine, which 

in turn leads to increased efficiency and lower emissions.
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All these options are technically feasible – there are 

numerous examples of each operating in the U.S. and worldwide. 

However, we do not find them to qualify as the best system for 

reduction of CO2 emissions for the following reasons: 

a. Lack of significant CO2 reductions when compared to business 

as usual

At the outset, we reviewed the emission rates of efficient 

PC and CFB units. According to the DOE/NETL estimates, a newly 

constructed subcritical PC unit firing bituminous coal would 

emit approximately 1,800 lb CO2/MWh-g,

531 a new highly efficient 

SCPC unit using bituminous coal would emit nearly 1,720 lb 

CO2/MWh-g, and a new IGCC unit would emit about 1,430 lb CO2/MWhg.

533,534 Emissions from comparable sources utilizing subbituminous coal or lignite will have somewhat higher CO2

emissions.535

 

531 Exhibit ES-2 from “Cost and Performance Baseline for Fossil 

Energy Plants Volume 1: Bituminous Coal and Natural Gas to 

Electricity”, Revision 2, Report DOE/NETL-2010/1397 (November 

2010).

533 “Cost and Performance Baseline for Fossil Energy Plants 

Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired Power 

Plants”, DOE/NETL-2015/1720 (June 2015); SCPC rates come from 

Exhibit A-2 and IGCC rates come from Exhibit A-4.

534 The comparable emissions on a net basis are: subcritical PC –

1,890 lb CO2/MWh-n; SCPC – 1,705 lb CO2/MWh-n; and IGCC – 1,724

lb CO2/MWh-n. (See same references as for gross emissions 

provided in the text).

535 Exhibit ES-2 from “Cost and Performance Baseline for Fossil 

Energy Plants Volume 3b: Low Rank Coal to Electricity: 

Combustion Cases”, Report DOE/NETL-2010/1463 (March 2011).
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Some commenters noted that new coal-fired plants utilizing 

supercritical boiler design or IGCC would provide substantial 

emission reductions compared to the emissions from the existing 

subcritical coal plants that are currently in wide use in the 

power sector. However, most of the recent new power sector 

projects using solid fossil fuel (coal or petroleum coke) as the 

primary fuel – both those that have been constructed and those 

that have been proposed – are supercritical boilers and IGCC 

units. About 60 percent of new coal-fired utility boiler 

capacity that has come on-line since 2005 was supercritical and 

of the new capacity that came on-line since 2010, about 70 

percent was supercritical. No new coal-fired utility boilers 

began operation in either 2013 or 2014. Coal-fired power plants 

that have come on-line most recently include AEP’s John W. Turk, 

Jr. Power Plant, which is a 600 MW ultra-supercritical536 PC 

(USCPC) facility located in the southwest corner of Arkansas, 

and Duke Energy’s Edwardsport plant, which is a 618 MW “CCS 

ready”537 IGCC unit located in Knox County, Indiana. Both of 

those facilities came on-line in 2012. It is likely that the

units that initiated operation in 2010 or later were conceived 

 

536 Ultra-supercritical (USC) and advanced ultra-supercritical 

(A-USC) are terms often used to designate a coal-fired power 

plant design with steam conditions well above the critical 

point.

537 A “CCS ready” facility is one that is designed such that the 

CCS equipment can be more easily added at a later time. 
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of, planned, designed, and permitted well before 2010 – likely 

in the early 2000s. Thus, it seems clear that the power sector 

had already, at that point, transitioned to the selection of 

supercritical boiler technology as “business as usual” for new 

coal-fired power plants. Since that time, there have been other 

coal-fired power plants that have been proposed and almost all 

of them have been either supercritical boiler designs or IGCC 

units. In Table 1 of the Technical Support Document Fossil FuelFired Boiler and IGCC EGU Projects Under Development: Status and 

Approach 539 for the January 2014 proposal, the EPA listed the 

development status of “potential transitional sources” (i.e., 

projects that had been proposed and had received Prevention of 

Significant Deterioration (PSD) preconstruction permits as of 

April 13, 2012). Of the 16 proposed EGU projects in Table 1 –

most of which have been cancelled or converted to or replaced 

with NGCC projects – the majority (nine) are either 

supercritical PC or IGCC designs. Five of the proposed projects

were CFB designs with only one being a subcritical PC design.

The EPA is aware of only one new coal-fired power plant 

that is actively in the construction phase. That plant is 

Mississippi Power’s Kemper County Energy Facility in Kemper 

County, MS – an IGCC unit that plans to begin operations in 2016 

 

539 Available in the rulemaking docket ID: EPA-HQ-OAR-2013-0495-

0024.
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and will implement partial CCS to capture approximately 65 

percent of the available CO2, which will be sold for use in EOR 

operations.

Considering the direction that the power sector has been 

taking and the changes that it is undergoing, identifying a new 

supercritical unit as the BSER and requiring an emission 

limitation based on the performance of such units thus would 

provide few, if any, additional CO2 emission reductions beyond 

the sector’s “business as usual”. As noted, for the most part, 

new sources are already designed to achieve at least that 

emission limitation. This criterion does not itself eliminate 

supercritical technology from consideration as BSER. However, 

existing technologies must be considered in the context of the 

range of technically feasible technologies and, as we discuss 

elsewhere in this final preamble, partial CCS can achieve 

emission limitations beyond business as usual and do so at a 

reasonable cost.

The EPA also considered IGCC technology and whether it 

represents the BSER for new power plants utilizing coal or other 

solid fossil fuels. IGCC units, on a gross-output basis, have 

inherently lower CO2 emission rates when compared to similarlysized SCPC units. However, the net emission rates and overall 

emissions to the atmosphere (i.e., tons of CO2 per year) tend to 

be more similar (though still somewhat lower) for new IGCC units 
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when compared to new SCPC units with the same electrical output. 

Therefore an emission limitation based on the expected 

performance of a new IGCC unit would result in some CO2 emission 

reductions from the segment of the industry that would otherwise 

construct new PC units, but not from the segment of the industry 

that would already construct new IGCC units. A gross-outputbased emission limitation consistent with the expected 

performance of a new IGCC unit would still require some 

additional control, such as partial CCS, on a new supercritical 

boiler.

As is shown in Section V.J and H, additional emission 

reductions beyond those that would result from an emission 

standard based on a new SCPC boiler or even a new IGCC unit as 

the BSER can be achieved at a reasonable cost. Because 

practicable emission controls are available that are of 

reasonable cost at the source level and that will have little 

cost and energy impact at the national level, the EPA is 

according significant weight to the factor of amount of 

emissions reductions in determining the BSER. As discussed 

above, the D.C. Circuit has emphasized this factor in describing

the purpose of CAA section 111 as to achieve “as much [emission 

reduction] as practicable.”540

 

540 Sierra Club, 657 F.2d at 327 & n. 83.
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b. Lack of incentive for technological innovation

As discussed above, the EPA is justifying its 

identification of the BSER based on its weighing of the factors 

explicitly identified in CAA section 111(a)(1), including the 

amount of the emission reduction. Under the D.C. Circuit case 

law, encouraging the development and implementation of advanced 

control technology must also be considered (and, in any case, 

may reasonably be considered; see Section V.H.3.d above).

Consideration of this factor confirms the EPA’s decision not to 

identify highly efficient generation technology (without CCS) as 

the BSER. At present, CCS technologies are the most promising 

options to achieve significant reductions in CO2 emissions from 

newly constructed fossil fuel-fired steam generating units. CCS 

technology is also now a viable retrofit option for some 

modified, reconstructed and existing sources – depending upon 

the configuration, location and age of those sources. As CCS 

technologies are deployed and used more there is an expectation 

that, based on previous experience with advanced technologies, 

the performance will improve and the implementation costs will 

decline. The improved performance and lower costs will provide 

additional incentive for further implementation in the future.
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The Intergovernmental Panel on Climate Change (IPCC) 

recently released its Fifth Assessment report541, which 

recognizes that widespread deployment of CCS is crucial to reach 

the long term climate goals. The authors of the report used 

models to predict the likelihood of stabilizing the atmospheric 

concentration of CO2 at 450 ppm by 2050 with or without carbon 

capture and storage (CCS). They found that several of the models 

were not able to reach this goal without CCS, which underlines 

the importance of deploying and further developing CCS on a 

large scale.

American Electric Power (AEP), in an evaluation of lessons 

learned from the Phase 1 of its Mountaineer CCS project, wrote: 

“AEP still believes the advancement of CCS is critical for the 

sustainability of coal-fired generation.”542

Some commenters felt that the proposed standard of 

performance for new steam generating units, based on 

implementation of partial CCS at an emission rate of 1,100 

lb/MWh-g, would not serve to promote the increased deployment 

and implementation of CCS. The commenters argued that such a 

 

541 IPCC, Working Group III, Climate Change 2014: Mitigation of 

Climate Change, http://mitigation2014.org/report/publication/.

542 CCS LESSONS LEARNED REPORT American Electric Power 

Mountaineer CCS II Project Phase 1, Prepared for The Global CCS 

Institute Project # PRO 004, January 23, 2012, page 2. See also 

AEP FEED Study at pp. 4, 63 (same). Available at: 

http://www.globalccsinstitute.com/publications/aep-mountaineerii-project-front-end-engineering-and-design-feed-report.
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standard could instead have the unintended result of 

discouraging the further development of advanced coal generating 

technologies such as ultra-supercritical boilers and improved 

IGCC designs. 

Commenters further argued that such a standard will stifle 

further development of CCS technologies. Commenters felt that 

the standard would effectively deter the construction of new 

coal-fired generation – and, if there is no new coal-fired 

generation, then there will be no implementation of CCS 

technology and, therefore, no need for continued research and 

development of CCS technologies. They argued, in fact, that the 

best way to promote the development of CCS was to set a standard 

that did not rely on it.

The EPA does not agree with these arguments and, in 

particular, does not see how a standard that is not predicated 

on performance of an advanced control technology would serve to 

promote development and deployment of that advanced control 

technology. On the contrary, the history of regulatory actions 

has shown that emission standards that are based on performance 

of advanced control equipment lead to increased use of that 

control equipment, and that the absence of a requirement stifles 

technology development.

There is a dramatic instance of this paradigm presented in 

the present record. In 2011, AEP deferred construction of a 
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large-scale CCS retrofit demonstration project on one of its 

coal-fired power plants because the state’s utility regulators 

would not approve cost recovery for CCS investments without a 

regulatory requirement to reduce CO2 emissions. AEP’s chairman 

was explicit on this point, stating in a July 17, 2011 press 

release announcing the deferral:

We are placing the project on hold until economic and 

policy conditions create a viable path forward ... We are clearly 

in a classic ‘which comes first?’ situation. The 

commercialization of this technology is vital if owners of coalfueled generation are to comply with potential future climate 

regulations without prematurely retiring efficient, costeffective generating capacity. But as a regulated utility, it is 

impossible to gain regulatory approval to recover our share of 

the costs for validating and deploying the technology without 

federal requirements to reduce greenhouse gas emissions already 

in place. The uncertainty also makes it difficult to attract 

partners to help fund the industry’s share.543

Some commenters also argued that the incremental cost 

associated with including CCS at the proposed level would 

prevent new coal-fired units from being built. Instead, they 

advocated for a standard based on most efficient technology 

 

543 http://www.aep.com/newsroom/newsreleases/?id=1704.
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(supercritical) coupled with government subsidies to advance and 

promote CCS technology. The final standard is less stringent 

than that proposed, and can be met at a lower cost than the 

proposed standard, and as explained above in Section V.H, the 

EPA has carefully evaluated those costs and finds them to be 

reasonable. Further, the record and current economic conditions 

(fuel costs, renewables, demand growth, etc.) show that noneconomic factors such as a desire for fuel diversity will likely 

drive future development of any new coal-fired EGUs. For this 

reason, the EPA does not find the commenters’ bare assertions

that the incremental cost of CCS (particularly as reasonably 

modulated for this final standard) would make the difference 

between constructing and not constructing new coal capacity to 

be persuasive. Rather, a cost-reasonable standard reflecting use 

of the new technology is what will drive new technology 

deployment.

The EPA expects that it is unlikely that a new IGCC unit 

would install partial CCS to meet the final standard unless the 

facility is built to take advantage of EOR opportunities or to 

operate as a poly-generation facility (i.e., to co-produce power 

along with chemicals or other products). For new IGCC units, the 

final standard of performance can be met by co-firing a small 

amount of natural gas. Some commenters argued that IGCC is an 

advanced technology that, like CCS, should be promoted. The EPA 
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agrees. IGCC is a low-emitting, versatile technology that can be 

used for purposes beyond just power production (as mentioned 

just above). Commenters further argued that a requirement to 

include partial CCS (at a level to meet the proposed standard of 

performance) would serve to deter – rather than promote – more 

installation of IGCC technology. We disagree with a similar 

argument that commenters make with respect to partial CCS for 

post-combustion facilities, but our final standard moots that 

argument for IGCC facilities because the final emission 

limitation of 1,400 lb CO2/MWh-g will not itself deter 

installation of IGCC technology, by the terms of the commenters’ 

own argument.

2. “Full” Carbon Capture and Storage (i.e., 90 Percent Capture) 

We also reconsidered whether the emission limitation for 

new coal-fired EGUs should be based on the performance of full 

implementation of CCS technology. For a newly constructed 

utility boiler, this would mean that a post-combustion capture 

system would be used to treat the entire flue gas stream to 

achieve an approximately 90 percent reduction in CO2 emissions. 

For a newly constructed IGCC unit, a pre-combustion capture 

system would be used to capture CO2 from a fully shifted 

gasification syngas stream to achieve an approximately 90 

percent reduction in CO2 emissions. 
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In the proposal for newly constructed sources, we found 

that “full CCS” would certainly result in significant CO2

reductions from any new source implementing the technology. 

However, we also found that the costs associated with 

implementation, on either a new utility boiler system or a new 

IGCC unit, are predicted to substantially exceed the costs for 

other dispatchable non-NGCC generating options that are being 

considered by utilities and project developers (e.g., new 

nuclear plants and new biomass-fired units). See 79 FR at 1477. 

This remains the case, and indeed, the difference between cost 

of full capture and new nuclear technology is estimated to be 

even greater than at proposal. The EPA thus is not selecting 

full capture CCS as BSER.

Q. Summary

The EPA finds that the best system of emission reduction 

adequately demonstrated is a highly efficient supercritical 

pulverized coal boiler using post-combustion partial CCS so that 

CO2 is captured, compressed and safely stored over the longterm. Properly designed, operated, and maintained, this best 

system can achieve a standard of performance of 1,400 lb CO2/MWhg, an emission limitation that is achievable over the 12-

operating-month compliance period considering usual operating 

variability (including use of different coal types, periods of 

startup and shutdown, and malfunction conditions). This 
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standard of performance is technically feasible, given that the 

BSER technology is already operating reliably in full-scale 

commercial application. The technology adds cost to a new 

facility which the EPA has evaluated and finds to be reasonable 

because the costs are in the same range as those for new nuclear 

generating capacity – a competing non-NGCC, dispatchable 

technology that utilities and project developers are also 

considering for base load application. The EPA has also 

considered capital cost increases associated with use of postcombustion partial CCS at the level needed to meet the final 

standard and found them to be reasonable, and within the range 

of capital cost increases for this industry in prior NSPS which 

have been adjudicated as reasonable. The EPA’s consideration of 

costs is also informed by its judgment that new coal-fired 

capacity would be constructed not as the most economic option, 

but for such purposes as preserving fuel diversity in an energy 

portfolio, and so would not be cost competitive with natural 

gas-fired capacity, so that some additional cost premium may 

therefore be reasonable. The EPA has carefully evaluated the 

non-air quality health and environmental impacts of the final 

standard and found them to be reasonable: CO2 pipelines and CO2

sequestration via deep well injection are subject already to 

rigorous control under established regulatory programs which 

assure prevention of environmental release during transport and 
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storage. In addition, water use associated with use of partial 

CCS at the level to meet the final standard is acceptable, and 

use of the technology does not impose significant burdens on 

energy requirements at either the plant or national level. The 

1,400 lb CO2/MWh-g standard reflecting performance of the BSER 

may be achieved without geographic constraint, both because 

geologic sequestration and EOR capacity are widely available and 

accessible, and also because alternative compliance pathways are 

available in the unusual circumstance where a new coal-fired 

plant is sited in an area without such access, that area has not 

already limited construction of new coal-fired capacity in some 

way, and the area cannot be serviced by coal-by-wire.

Accordingly, the EPA finds that the promulgated standard of 

performance for new fossil fuel-fired steam electric generating 

units satisfies the requirements of CAA section 111(a).

VI. Rationale for Final Standards for Modified Fossil Fuel-fired 

Electric Utility Steam Generating Units

The EPA has determined that, as proposed, the BSER for 

steam generating units that trigger the modification provisions 

is each affected unit’s own best potential performance as 

determined by that unit’s historical performance. The final 

standards of performance are similar to those proposed in the 

June 2014 proposal. Differences between the proposed standards 

and the final standards issued in this action reflect responses 
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to comments received on the proposal. Those changes are 

described below. 

As noted previously, the EPA is issuing final emission 

standards only for affected modified steam generating units that 

conduct modifications resulting in a hourly increase in CO2

emissions (mass per hour) of more than 10 percent ("large" 

modifications). The EPA is continuing to review the appropriate 

standards for modified sources that conduct modifications 

resulting in a hourly increase in CO2 emissions (mass per hour) 

of less than or equal to 10 percent ("small" modifications), is 

not issuing final standards for those sources in this action, 

and is withdrawing the proposed standards for those sources. See 

Section XV below.

A. Rationale for Final Applicability Criteria for Modified Steam 

Generating Units

Final applicability criteria for modified steam generating 

EGUs include those discussed earlier in Section III.A.1 (General 

Applicability) and Section III.A.3 (Applicability Specific to 

Modified Sources). 

CAA section 111(a)(4) defines a “modification” as “any 

physical change in, or change in the method of operation of, a 

stationary source which increases the amount of any air 

pollutant emitted by such source or which results in the 

emission of any air pollutant not previously emitted.” Certain 
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types of physical or operational changes are exempt from 

consideration as a modification. Those are described in 40 CFR 

60.2, 60.14(e). To be clear, our action in this final rule, and 

the discussion below, does not change anything concerning what 

constitutes or does not constitute a modification under the CAA 

or the EPA’s regulations.545

A modified steam generating unit is a source that fits the 

definition and applicability criteria of a fossil fuel-fired 

steam generating unit and that commences a qualifying 

modification on or after June 18, 2014 (the publication date of 

the proposed modification standards). 79 FR 34960.

For the reasons discussed below, the EPA in this final 

action is finalizing requirements only for steam generating 

units that conduct modifications resulting in an increase in 

hourly CO2 emissions (mass per hour) of more than 10 percent as 

compared to the source’s highest hourly emission during the 

previous five years. With respect to modifications with smaller 

increases in CO2 emissions (specifically, steam generating units 

that conduct modifications resulting in an increase in hourly CO2

emissions (mass per hour) of 10 percent or less compared to the 

source’s highest hourly emission during the previous 5 years),

 

545 CAA section 111(a)(4); See also 40 CFR 60.14 concerning what 

constitutes a modification, how to determine the emission rate, 

how to determine an emission increase, and specific actions that 

are not, by themselves, considered modifications.
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the EPA is not finalizing any standard or other requirements, 

and is withdrawing the June 2014 proposal with respect to these 

sources (see Section XV below).

The effect of the EPA’s deferral on setting standards for 

sources undertaking modifications resulting in smaller increases 

in CO2 emissions and the withdrawal of the June 2014 proposal 

with respect to such sources is that such sources will continue 

to be existing sources and subject to requirements under section 

111(d). This is because an existing source does not always 

become a new source when it modifies. Under the definition of 

“new source” in section 111(a)(2), an existing source only 

becomes a new source if it modifies after the publication of 

proposed or final regulations that will be applicable to it. 

Thus, if an existing source modifies at a time that there is no 

promulgated final standard or pending proposed standard that 

will be applicable to it as a modified “new” source, that source 

is not a new source and continues to be an existing source. 

Here, because the EPA is not finalizing standards for sources 

undertaking modifications resulting in smaller increases in CO2

emissions and is withdrawing the proposal with respect to such 

sources, these sources do not fall within the definition of “new 

source” in section 111(a)(2) and continue to be an “existing 

source” as defined in section 111(a)(6). See Section XV below.

As we discussed in the June 2014 proposal, the EPA has
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historically been notified of only a limited number of NSPS 

modifications546 involving fossil steam generating units and 

therefore predicted that very few of these units would trigger 

the modification provisions and be subject to the proposed 

standards. Given the limited information that we have about past 

modifications, the agency has concluded that it lacks sufficient 

information to establish standards of performance for all types 

of modifications at steam generating units at this time. 

Instead, the EPA has determined that it is appropriate to 

establish standards of performance at this time for larger

modifications, such as major facility upgrades involving, for 

example, the refurbishing or replacement of steam turbines and 

other equipment upgrades that result in substantial increases in 

a unit’s hourly CO2 emissions rate. The agency has determined, 

based on its review of public comments and other publicly 

available information, that it has adequate information 

regarding the types of modifications that could result in large 

increases in hourly CO2 emissions, as well as on the types of 

measures available to control emissions from sources that 

undergo such modifications, and on the costs and effectiveness 

of such control measures, upon which to establish standards of 

performance for modifications with large emissions increases at 

 

546 NSPS modifications resulting in increases in hourly emissions 

of criteria pollutants.
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this time.

In establishing standards of performance at this time for 

modifications with large emissions increases, but not for those 

with small increases, the EPA is exercising its policy 

discretion to promulgate regulatory requirements in a sequential 

fashion for classes of modifications within a source category, 

accounting for the information available to the agency, while 

also focusing initially on those modifications with the greatest 

potential environmental impact. This approach is consistent with 

the case law that authorizes agencies to establish a regulatory 

framework in an incremental fashion, that is, a step at a 

time.547

 

547 As the U.S. Supreme Court recently stated in Massachusetts v. 

EPA, 549 U.S. 497, 524 (2007): “‘Agencies, like legislatures, do 

not generally resolve massive problems in one fell regulatory 

swoop;’” and instead they may permissibly implement such 

regulatory programs over time, “‘refining their preferred 

approach as circumstances change and as they develop a more 

nuanced understanding of how best to proceed.’” See Grand Canyon 

Air Tour Coalition v. F.A.A., 154 F.3d 455 (D.C. Cir. 1998), 

City of Las Vegas v. Lujan, 891 F.2d 927, 935 (D.C. Cir. 1989), 

National Association of Broadcasters v. FCC, 740 F.2d 1190, 

1209–14 (DC Cir. 1984). See also, Hazardous Waste Treatment 

Council v. U.S. E.P.A., 861 F.2d 277, 287 (D.C. Cir. 1988)

("[A]n agency's failure to regulate more comprehensively is not 

ordinarily a basis for concluding that the regulations already 

promulgated are invalid. 'The agency might properly take one 

step at a time.' United States Brewers Assoc. v. EPA, 600 F.2d 

974,982 (D.C. Cir. 1979). Unless the agency's first step takes 

it down a path that forecloses more comprehensive regulation, 

the first step is not assailable merely because the agency 

failed to take a second. The steps may be too plodding, but 

that raises an entirely different issue . . . .").
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To be clear, the EPA is not reaching a final decision as to 

whether it will regulate modifications with smaller increases, 

or even that such modifications should be subject to different 

requirements than we are finalizing in this rule for the 

modifications with larger increases. We have made no decisions 

and this matter is not concluded. We plan to continue to gather 

information, consider the options for modifications with smaller 

increases, and, in the future, develop a proposal for these 

modifications or otherwise take appropriate steps.

As a means of determining the proper threshold between the 

larger and smaller increases in CO2 emissions, the EPA examined 

changes in CO2 emissions that may result from large, capitalintensive projects, such as major facility upgrades involving 

the refurbishing or replacement of steam turbines and other 

equipment upgrades that would significantly increase a unit's 

capacity to burn more fossil fuel, thereby resulting in large 

emissions increases. Major upgrades such as these could increase 

a steam generating unit's hourly CO2 emissions by well over 10 

percent.

550

An example of such major upgrade would be work performed at 

AmerenUE’s Labadie Plant, a facility with four 600-MW (nominal) 

 

550 See e.g., Power Engineering, Steam Turbine Upgrades Boost 

Plant Reliability, Efficiency, available at www.powereng.com/articles/print/volume-116/issue-11/features/steamturbine-upgrades-boost-plant-reliability-efficiency.html.
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coal-fired units located 35 miles west of St. Louis. In the 

early 2000s, plant staff conducted process improvements that 

raised maximum unit capacity by nearly 10 percent (from 580 MW 

to 630 MW).551 Those changes included boiler improvements 

necessitated by its switch from bituminous to subbituminous 

coal552, installation of low-NOX burners, an overfire air system, 

and advanced computer controls. One of the performance gains 

came from upgrading all four steam turbines, which AmerenUE 

chose to replace as modules allowing engineers more freedom to 

maximize performance unconstrained by the units’ existing outer 

casing.

Another example is the refurbishment of the 2,100 MW Eskom 

Arnot coal-fired power plant in South Africa with a resulting 

increase in its power output by 300 MW to 2,400 MW – an increase 

in capacity of 14 percent.553 For each of the plant’s six steam 

generating units, the company conducted a complete retrofit of

the high pressure and intermediate pressure steam turbines, a 

capacity upgrade of the low pressure steam turbine, and the 

replacement and upgrade of associated turbine side pumps and 

 

551 “Steam turbine upgrading: Low-hanging fruit”, Power 

(04/15/2006), www.powermag.com/steam-turbine-upgrading-lowhanging-fruit.

552 Note that a change in coal-type or change in the use of other 

raw material does not necessarily constitute an “operational 

change”. See 40 CFR 60.14(e)(4). 

553 www.alstom.com/press-centre/2006/10/alstom-signs-power-plantupgrade-and-retrofit-contract-with-eskom-in-south-africa/.
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auxiliaries. In addition, major upgrades to the boiler plant 

were conducted, including supply of new pressure part 

components, new burners, and modification to other equipment 

such as the coal mills and classifiers, fans, and heaters. Other 

examples are provided in a technical memo available in the 

rulemaking docket.554

The EPA does not intend to imply that these specific 

projects would have resulted in an increase in hourly CO2

emissions of greater than 10 percent. Capacity increases are 

often the result of efficient improvements or are accompanied by 

other facility improvements that can offset emissions increases

due to increased fuel input capacity. However, these examples 

are intended to show the types of large, more capital intensive 

projects that can potentially result in increases in hourly 

emissions of CO2 of at least 10 percent.

The EPA believes that it is reasonable to set the threshold 

between “large” modifications and “small” modifications at 10 

percent, a level commensurate with the magnitude of the 

emissions increases that could result from the types of projects

described above, and we are issuing a final standard of 

performance for those sources that conduct modifications 

 

554 See “U.S. DOE Information Relevant to Technical Basis for 

“Large Modification” Threshold” available in the rulemaking 

docket EPA-HQ-OAR-2013-0495.
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resulting in hourly CO2 emission increases that exceed that 

threshold. We are not issuing standards of performance for those 

sources that conduct modifications resulting in an hourly 

increase of CO2 emissions of less than or equal to 10 percent. 

Therefore, the EPA is withdrawing the proposed standards 

for those sources that conduct modifications resulting in a

hourly increase in CO2 emissions (mass per hour) of less than or 

equal to ten percent and is not issuing final standards for 

those sources at this time. See Section XV below. Utilities, 

states and others should be aware that the differentiation 

between modifications with larger and smaller increases in CO2

emissions only applies to sources covered under 40 CFR part 60,

subpart TTTT, i.e., it is only applicable to CO2 emissions from 

fossil fuel-fired steam generating units. There is no similar 

provision for criteria pollutants or for other source 

categories. Utilities, states and others should also be aware 

that the distinction between large and small modifications only 

applies to NSPS modifications. Sources undertaking modifications 

may still be subject to requirements of New Source Review under 

CAA Title I part C or D (which have different standards for 

modifications than the NSPS and require a case-by-case analysis)

or other CAA requirements.

The EPA notes that some commenters expressed concern that a 

number of existing fossil steam generating units, in order to 
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fulfill requirements of an approved CAA section 111(d) plan, may 

pursue actions that involve physical or operational changes that 

result in some increase in their CO2 emissions on an hourly 

basis, and thus constitute modifications. Some commenters 

suggested that the EPA should exempt projects undertaken 

specifically for the purpose of complying with CAA section 

111(d).

The EPA does not have sufficient information at this time 

to predict the full array of actions that existing steam 

generating units may undertake in response to applicable 

requirements under an approved CAA section 111(d) plan, or 

which, if any, of these actions may result in increases in CO2

hourly emissions. Nevertheless, the EPA expects that, to the 

extent actions undertaken by existing steam generating units in 

response to 111(d) requirements trigger modifications, the 

magnitude of the increases in hourly CO2 emissions associated 

with such modifications would generally be smaller and would 

therefore generally not subject such modifications to the 

standards of performance that the EPA is finalizing in this rule

for modified steam generating units with larger increases in

hourly CO2 emissions.

B. Identification of the Best System of Emission Reduction

The EPA has determined that, as was proposed, the BSER for 

steam generating units that trigger the modification provisions 
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is the affected EGU’s own best potential performance as 

determined by that source’s historical performance. 

The EPA proposed that the BSER for modified steam 

generating EGUs is each unit’s own best potential performance 

based on a combination of best operating practices and equipment 

upgrades. Specifically, the EPA co-proposed two alternative 

standards for modified utility steam generating units. In the 

first co-proposed alternative, modified steam generating EGUs 

would be subject to a single emission standard determined by the

affected EGU’s best demonstrated historical performance (in the 

years from 2002 to the time of the modification) with an 

additional 2 percent emission reduction. The EPA proposed that 

the standard could be met through a combination of best 

operating practices and equipment upgrades. To account for 

facilities that have already implemented best practices and 

equipment upgrades, the proposal also specified that modified 

facilities would not have to meet an emission standard more 

stringent than the corresponding standard for reconstructed 

EGUs. 

The EPA also co-proposed that the specific standard for 

modified sources would be dependent on the timing of the 

modification. We proposed that sources that modify prior to 

becoming subject to a CAA section 111(d) plan would be required 

to meet the same standard described in the first co-proposal—
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that is, the modified source would be required to meet a unitspecific emission limit determined by the affected EGU’s best 

demonstrated historical performance (in the years from 2002 to 

the time of the modification) with an additional 2 percent 

emission reduction (based on equipment upgrades). We also 

proposed that sources that modify after becoming subject to a 

CAA section 111(d) plan would be required to meet a unitspecific emission limit that would be determined by the CAA 

section 111(d) implementing authority and would be based on the 

source’s expected performance after implementation of identified 

unit-specific energy efficiency improvement opportunities.

The final standards in this action do not depend upon when 

the modification commences (as long as it commences after June 

8, 2014). The EPA received comments on the June 2014 proposal

that called into question the need to differentiate the standard 

based on when the modification was undertaken. Further,

commenters noted that the proposed requirements for sources 

modifying after becoming subject to a CAA section 111(d) plan, 

which were based on energy efficiency improvement opportunities 

were vague and that standard setting under CAA section 111(b) is 

a federal duty and would require notice-and-comment rulemaking. 

The EPA considered those comments and has determined that we 

agree that there is no need for subcategories based on the 

timing of the modification. 
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C. BSER Criteria 

1. Technical Feasibility

The EPA based technical feasibility of the unit-specific 

efficiency improvement on analyses done to support heat rate 

improvement for the proposed CAA section 111(d) emission 

guidelines (Clean Power Plan). That work was summarized in 

Chapter 2 of the TSD, “GHG Abatement Measures”.556 In response to 

comments on the proposed Clean Power Plan, the approach was 

adjusted, as described in the final CAA section 111(d) emission 

guidelines. As with proposed actions, the EPA is basing 

technical feasibility for final standards for modified source 

efficiency improvements on the analyses for heat rate 

improvements for the CAA 111(d) final rule.

2. Cost

Any efficiency improvement made by EGUs for the purpose of 

reducing CO2 emissions will also reduce the amount of fuel that 

EGUs consume to produce the same electricity output. The cost 

attributable to CO2 emission reductions, therefore, is the net 

cost of achieving heat rate improvements after any savings from 

reduced fuel expenses. As summarized below, we estimate that, on 

average, the savings in fuel cost associated with a 4 percent 

heat rate improvement would be sufficient to cover much of the 

 

556 Technical Support Document “GHG Abatement Measures” available 

in the rulemaking docket EPA-HQ-OAR-2013-0495.
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associated costs, and thus that the net costs of heat rate 

improvements associated with reducing CO2 emissions from affected 

EGUs are relatively low.

We recognize that our cost analysis just described will 

represent the costs for some EGUs better than others because of 

differences in EGUs’ individual circumstances. We further 

recognize that reduced generation from coal-fired EGUs will tend 

to reduce the fuel savings associated with heat rate 

improvements, thereby raising the effective cost of achieving 

the CO2 emission reductions from the heat rate improvements. 

Nevertheless, we still expect that the majority of the 

investment required to capture the technical potential for CO2

emission reductions from heat rate improvements would be offset 

by fuel savings, and that the net costs of implementing heat 

rate improvements as an approach to reducing CO2 emissions from 

modified fossil fuel-fired EGUs are reasonable. The EPA further 

notes that the types of large, more capital intensive projects 

that may trigger the “larger modifications” threshold (i.e., 

result in an hourly increase in CO2 emissions) often are 

undertaken in order to increase the capacity of the source but 

also to improve the heat rate or efficiency of the unit.

3. Emission Reductions

This approach would achieve reasonable reductions in CO2

emissions from the affected modified units as those units will 
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be required to meet an emission standard that is consistent with 

more efficient operation. In light of the limited opportunities 

for emission reductions from retrofits, these reductions are 

adequate.

4. Promotion of Technology and Other Systems of Emission 

Reduction

As noted previously, the case law makes clear that the EPA 

is to consider the effect of its selection of the BSER on 

technological innovation or development, but that the EPA also 

has the authority to weigh this factor, along with the various 

other factors. With the selection of emissions controls, 

modified sources face inherent constraints that newly 

constructed greenfield and even reconstructed sources do not; as 

a result, modified sources present different, and in some ways 

more limited, opportunities for technological innovation or 

development. In this case, the standards promote technological 

development by promoting further development and market 

penetration of equipment upgrades and process changes that 

improve plant efficiency.
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VII. Rationale for Final Standards for Reconstructed Fossil 

Fuel-fired Electric Utility Steam Generating Units 

A. Rationale for Final Applicability Criteria for Reconstructed 

Sources

The applicability rationale for reconstructed utility steam 

generating units is the same as for newly constructed utility 

steam generating units. We are finalizing the same general 

criteria and not amending the reconstruction provisions included 

in the general provisions. 

B. Identification of the Best System of Emission Reduction

In the proposal, the EPA evaluated seven different control 

technology configurations to determine the BSER for 

reconstructed fossil fuel-fired boiler and IGCC EGUs: (1) The 

use of partial CCS, (2) conversion to (or co-firing with) 

natural gas, (3) the use of CHP, (4) hybrid power plants, (5) 

reductions in generation associated with dispatch changes, 

renewable generation, and demand side energy efficiency,(6) 

efficiency improvements achieved through the use of the most 

efficient generation technology, and (7) efficiency improvements 

achieved through a combination of best operating practices and 

equipment upgrades. 

Although the EPA concluded that the first 4 technologies 

met most of the evaluation criteria, namely they are adequately 

demonstrated, have reasonable costs and provide GHG emissions 
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reductions, they were inappropriate for BSER due to site 

specific constraints for existing EGUs on a nationwide basis. We 

rejected best operating practices and equipment upgrades because

we concluded the GHG reductions are not sufficient to qualify as 

BSER. The majority of commenters agree with the EPA's decision 

that these technologies are not BSER. In contrast, as described 

in more detail later in this section a few commenters did 

support partial CCS as BSER. 

The fifth option, reductions in generation associated with 

dispatch changes, renewable generation, and demand side energy 

efficiency, is comparable to application of measures identified 

in building blocks two, three and four in the emissions 

guidelines that we proposed under CAA section 111(d). We 

solicited comment on any additional considerations that the EPA 

should take into account in the applicability of building blocks 

two, three and four in the BSER determination. Most commenters 

stated that building blocks two, three and four should not be 

considered for reconstructed sources. 

The proposed BSER was based on the performance of the most 

efficient generation technology available, which we concluded 

was the use of the best available subcritical steam conditions 

for small units and the use of supercritical steam conditions 

for large units. We concluded this technology to be technically 

feasible, to have sufficient emission reductions, to have
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reasonable costs, and some opportunity for technological 

innovation. The proposed emission standard for these sources was 

1,900 lb CO2/MWh-n for units with a heat input rating of greater 

than 2,000 MMBtu/h and 2,100 lb CO2/MWh-n for units with a heat 

input rating of 2,000 MMBtu/h or less. The difference in the 

proposed standards for larger and smaller units was based on 

greater availability of higher pressure/temperature steam 

turbines (e.g. supercritical steam turbines) for larger units. 

As explained in Section III of this preamble, we are finalizing 

the standard on a gross output basis for utility steam 

generating units. The equivalent gross-output-based standards 

are 1,800 lb CO2/MWh and 2,000 lb CO2/MWh respectively.

We solicited comment on multiple aspects of the proposed 

standards. First, we solicited comment on a range of 1,600 to 

2,000 lb CO2/MWh-g for large units and 1,800 to 2,200 lb CO2/MWhg for small units. We also solicited comment on whether the 

standards for utility boilers and IGCC units should be 

subcategorized by primary fuel type. In addition, we solicited 

comment on if there are sufficient alternate compliance 

technologies (e.g., co-firing natural gas) that the small unit 

subcategory is unnecessary and should be eliminated. Those small 

sources would be required to meet the same emission standard as 

large utility boilers and IGCC units.
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Many commenters supported the upper limits of the suggested 

ranges, saying the standard will be consistently met. Some 

commenters raised concerns about the achievability of these 

limits for the many boiler and fuel types. A few commenters 

suggested that there should be separate subcategories for coalfired utility boilers and IGCC units, since IGCC units have 

demonstrated limits closer to 1,500 lb CO2/MWh-n and the units' 

designs are so fundamentally different. Some commenters said

that CFB (due to lower maximum steam temperatures), IGCC, and 

traditional boilers each need their own subcategory. Some 

commenters suggested that due to high moisture content and high 

relative CO2 emissions of lignite, lignite-fired units should 

have its own subcategory. Other commenters opposed the proposed 

standards for reconstructed units because they thought the BSER 

determination for reconstructed subpart Da units was 

inconsistent with the BSER determination for newly constructed

units. These commenters stated that the EPA did not provide 

sufficient justification for eliminating partial carbon capture 

and sequestration (CCS). These commenters also stated that the 

reason the EPA gave for dismissing CCS in the proposal was a 

lack of "sufficient information about costs." These commenters 

hold that the cost rationale does not apply for reconstructed 

coal-fired power plants. The fact that reconstructed units may 

face greater costs to comply with a CAA section 111(b) standard 
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than new sources does not relieve them of their compliance 

obligation.

Based on a review of the comments, we have concluded that 

both the proposed BSER and emission standards are appropriate, 

and we are finalizing the standards as proposed. Nothing in the 

comments changed our view that the BSER for reconstructed steam 

generating units should be based on the performance of a well 

operated and maintained EGU using the most efficient generation 

technology available, which we have concluded is a supercritical 

pulverized coal (SCPC) or supercritical circulating fluidized 

bed (CFB) boiler for large units, and subcritical for small 

units. As described at proposal, we have concluded that these 

standards are achievable by all the primary coal types. The 

final standards for reconstructed utility boilers and IGCC units 

is 1,800 lb CO2/MWh-g for sources with a heat input rating of 

greater than 2,000 MMBtu/h and 2,000 lb CO2/MWh-g for sources 

with a heat input rating of 2,000 MMBtu/h or less. 

While the final emission standards are based on the 

identified BSER, a reconstructed EGU would not necessarily have 

to rebuild the boiler to use steam temperatures and pressures 

that are higher than the original design. As commenters noted, a 

reconstructed unit is not required to meet the standards if 

doing so is deemed to be "technologically and economically" 

infeasible. 40 CFR 60.15(b). This provision inherently requires 
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case-by-case reconstruction determinations in the light of 

considerations of economic and technological feasibility. 

However, this case-by-case determination would consider the 

identified BSER (the use of the best available steam 

conditions), as well as-- at a minimum-- the first four 

technologies the EPA considered, but rejected, as BSER for a 

nationwide rule. One or more of these technologies could be 

technically feasible and reasonable cost, depending on site 

specific considerations and, if so, would likely result in 

sufficient GHG reductions to comply with the applicable 

reconstructed standards. Finally, in some cases, equipment 

upgrades and best operating practices would result in sufficient 

reductions to achieve the reconstructed standards.

VIII. Summary of Final Standards for Newly Constructed and 

Reconstructed Stationary Combustion Turbines

This section summarizes the final applicability

requirements, BSER determinations, and emission standards for 

newly constructed and reconstructed stationary combustion 

turbines. In addition, it also summarizes significant 

differences between the proposed and final provisions.

A. Applicability Requirements

We are finalizing BSER determinations and emission 

standards for newly constructed and reconstructed stationary

combustion turbines that (1) have a base load rating for fossil 
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fuels greater than 260 GJ/h (250 MMBtu/h) and (2) serve a 

generator capable of selling more than 25 MW-net of electricity 

to the grid. We also are finalizing applicability requirements 

that will exempt from the final standards (1) all stationary 

combustion turbines that are dedicated non-fossil fuel-fired 

units (i.e., combustion turbines capable of combusting 50 

percent or more non-fossil fuel) and subject to a federally 

enforceable permit condition restricting annual fossil fuel use 

to 10 percent or less of a unit’s annual heat input capacity; 

(2) the large majority of industrial CHP units (i.e., CHP 

combustion turbines that are subject to a federally enforceable 

permit condition limiting annual net-electric sales to the 

product of the unit’s net design efficiency multiplied by the 

unit’s potential output, or 219,000 MWh, whichever is greater); 

(3) combustion turbines that are physically incapable of burning 

natural gas (i.e., not connected to a natural gas pipeline); and 

(4) municipal waste combustors and commercial or industrial 

solid waste incinerators (units subject to subparts Eb or CCCC 

of this part).

For combustion turbines subject to an emission standard, we 

are finalizing three subcategories: base load natural gas-fired 

units, non-base load natural gas-fired units, and multi-fuelfired units. We use the term base load natural gas-fired units 

to refer to stationary combustion turbines that (1) burn over 90 
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percent natural gas and (2) sell electricity in excess of their 

design efficiency (not to exceed 50 percent) multiplied by their 

potential electric output. To be in this subcategory, a 

stationary combustion turbine must exceed the “natural gas-use 

criterion” on a 12-operation month rolling average and the 

“percentage electric sales” criterion on both a 12-operatingmonth and 3-year rolling average basis. We use the term non-base 

load natural gas-fired units to refer to stationary combustion 

turbines that (1) burn over 90 percent natural gas and (2) have 

net-electric sales equal to or below their design efficiency 

(not to exceed 50 percent) multiplied by their potential 

electric output. These criteria are calculated on the same 

rolling average bases as for the base load subcategory. Finally, 

we use the term multi-fuel-fired units to refer to stationary 

combustion turbines that burn 10 percent or more non-natural gas 

on a 12-operating-month rolling average basis. We are not 

finalizing the proposed emission standards for modified sources

and are withdrawing those standards. We explain our rationale 

for these final decisions in Sections IX and XV of this 

preamble.

B. Best System of Emission Reduction

We are finalizing BSER determinations for the three 

subcategories of stationary combustion turbines referred to 

above: base load natural gas-fired units, non-base load natural 
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gas-fired units, and multi-fuel-fired units. For newly 

constructed and reconstructed base load natural gas-fired 

stationary combustion turbines, the BSER is the use of efficient 

NGCC technology. For newly constructed and reconstructed nonbase load natural gas-fired stationary combustion turbines, the

BSER is the use of clean fuels (i.e., natural gas with an 

allowance for a small amount of distillate oil). For multi-fuelfired stationary combustion turbines, the BSER is also the use 

of clean fuels (e.g., natural gas, ethylene, propane, naphtha, 

jet fuel kerosene, distillate oils 1 and 2, biodiesel, and 

landfill gas).

C. Final Emission Standards

For all newly constructed and reconstructed base load

natural gas-fired combustion turbines, we are finalizing an 

emission standard of 1,000 lb CO2/MWh-g, calculated on a 12-

operating-month rolling average basis. We are also finalizing an 

optional emission standard of 1,030 lb CO2/MWh-n, calculated on a 

12-operating-month rolling average basis, for stationary 

combustion turbines in this subcategory. For newly constructed 

and reconstructed non-base load natural gas-fired combustion 

turbines, we are finalizing a standard of 120 lb CO2/MMBtu, 

calculated on a 12-operating-month rolling average basis. For 

newly constructed and reconstructed multi-fuel-fired combustion 

turbines, we are finalizing a standard of 120 to 160 lb 
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CO2/MMBtu, calculated on a 12-operating-month rolling average 

basis. The emission standard for multi-fuel-fired combustion 

turbines co-firing natural gas with other fuels shall be 

determined at the end of each operating month based on the 

percentage of co-fired natural gas. Table 15 summarizes the 

subcategories, BSER determinations, and emission standards for 

combustion turbines.

Table 15: Combustion Turbine Subcategories and BSER

D. Significant Differences between Proposed and Final Combustion 

Turbine Provisions

As shown in Tables 16 and 17 below, the proposed rule 

included several general applicability criteria and two 

subcategorization criteria for combustion turbines. In addition 

to the proposed applicability and subcategorization framework, 

we solicited comment on a "broad applicability approach" that 

 

557 The emission standard for combustion turbines co-firing 

natural gas with other fuels shall be determined based on the 

amount of co-fired natural gas at the end of each operating 

month. 

Subcategory BSER Emission standard

Base load natural 

gas-fired 

combusiton turbines

Efficient NGCC 1,000 lb CO2/MWhg or 1,030 lb 

CO2/MWh-n

Non-base load 

natural gas-fired 

combustion turbines

Clean fuels 120 lb CO2/MMBtu

Multi fuel-fired 

combustion turbines

Clean fuels 120 to 160 lb 

CO2/MMBtu557
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included most combustion turbines irrespective of the actual 

amount of electricity sold to the grid or the actual amount of 

natural gas burned (i.e., non-base load units and multi-fuelfired units, respectively). The broad applicability approach 

changed the proposed "percentage electric sales" and "natural 

gas-use" criteria to distinguish among subcategory-specific 

emissions standards. Specifically, in the broad applicability 

approach, we solicited comment on subjecting non-base load units 

and multi-fuel-fired units to "no emissions standard," while 

still including them in the general applicability. We also 

solicited comment on establishing a separate numerical standard

for non-base load units. The final rule retains all of the 

proposed applicability criteria in some form, but most closely 

tracks the broad applicability approach by finalizing the 

percentage electric sales and natural gas-use criteria as 

thresholds that distinguish among three subcategories of 

combustion turbines with separate emissions standards.

The final rule also includes exceptions to the broad 

applicability approach that we solicited comment on, with some 

changes that are responsive to public comments. Categorical 

exceptions to the broad applicability criteria are the 

exclusions for CHP units, non-fossil fuel units, and combustion 

turbines not able to combust natural gas. First, the proposed 

applicability criteria did not include CHP units that were 
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constructed for the purpose of or that actually sell one-third 

or less of their potential electric output or 219,000 MWh, 

whichever is greater, to the grid. The final rule eliminates the 

“constructed for the purpose of” and actual sales aspects of the 

proposal and replaces them with an exemption for CHP units that 

take federally enforceable permit conditions restricting netelectric sales to a percentage of potential electric sales based 

on the unit’s design efficiency or 219,000 MWh, whichever is 

greater. Second, the proposed applicability criteria did not 

include non-fossil fuel units that burn 10 percent or less 

fossil fuel on a 3-year rolling average. The final rule 

similarly replaces the actual fuel-use aspect of the proposal 

with an exemption for non-fossil fuel units that take federally 

enforceable permit conditions limiting fossil-fuel use to 10 

percent or less of annual heat input capacity. Finally, the 

proposed applicability criteria did not include combustion 

turbines that burn 90 percent or less natural gas on a 3-year 

rolling average basis. In contrast, the final rule includes most 

fossil fuel-fired combustion turbines regardless of the amount 

of natural gas burned, with an exception for combustion turbines 

that are not connected to natural gas pipelines. Finally, in 

response to public comments, we are not finalizing the

subcategories for large and small combustion turbines that were 

contained in the proposal. Instead, all base load natural gas-
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fired combustion turbines must meet an emission standard of 

1,000 lb CO2/MWh-g.

Table 16: Proposed Applicability Criteria versus Final 

Applicability Criteria

Applicability 

Criteria Proposed Applicability Final Applicability 

Base load 

rating

criterion

Base load rating > 73 MW 

(250 MMBtu/h)

Base load rating > 260 

GJ/h558 (250 MMBtu/h)

Total electric 

sales 

criterion

Constructed for purpose 

of and actually selling > 

219,000 MWh-n to the grid

Ability to sell > 25 

MW-n to the grid

Percentage 

electric sales 

criterion

Constructed for purpose 

of and having actual netsales to the grid > onethird of potential 

electric output

Changed to 

subcategorization 

criterion per broad 

applicability approach

Natural gasuse criterionActually burns > 90 

percent natural gas

 Changed to 

subcategorization 

criterion per broad 

applicability 

approach

 Exemption for 

combustion turbines 

that are not 

connected to a 

natural gas supply

Fossil fueluse criterionActually burns > 10

percent fossil fuel

Exemption based on 

permit condition 

limiting amount of 

fossil fuel burned to 

≤ 10 percent of annual

heat input capacity

Combined Heat 

and Power 

(CHP) 

NA Exemption based on 

permit condition 

limiting net-electric 

 

558 73 MW is equivalent to 260 GJ/h. We changed units to avoid 

potential confusion of MW referring to electric output rather 

than heat input.
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exemption sales to ≤ design 

efficiency multiplied 

by potential electric 

output, or 219,000 

MWh-n, whichever is 

greater

Non-EGU 

exemption

Exemption for municipal 

solid waste combustors 

and commercial or 

industrial solid waste 

incinerators

Same as proposal

Table 17: Proposed Subcategories versus Final Subcategories

Subcategory Proposed 

Criteria

Final Criteria

Small 

combustion 

turbine

subcategory

Base load

rating ≤ 850 

MMBtu/h

NA

Large 

combustion 

turbine

subcategory

Base load

rating > 850 

MMBtu/h

NA

Base load 

natural gasfired base 

load 

combustion 

turbine 

subcategory

NA  Actually burns > 90 percent 

natural gas

 Net-electric sales > design 

efficiency (not to exceed 50 

percent) multiplied by 

potential electric output

Non-base load 

natural gasfired 

combustion 

turbine 

subcategory

NA  Actually burns > 90 percent

natural gas

 Net-electric sales ≤ design 

efficiency (not to exceed 50 

percent) multiplied by 

potential electric output

Multi-fuelfired 

combustion 

turbine

subcategory

NA Actually burns ≤ 90 percent

natural gas
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IX. Rationale for Final Standards for Newly Constructed and 

Reconstructed Stationary Combustion Turbines

This section discusses the EPA’s rationale for the final

applicability criteria, BSER determinations, and standards of 

performance for newly constructed and reconstructed stationary

combustion turbines. In this section, we present a summary of 

what we proposed, a selection of the significant comments we 

received, and our rationale for the final determinations, 

including how the comments influenced our decision-making. 

A. Applicability

This section describes the proposed applicability criteria, 

applicability issues we specifically solicited comment on, the 

relevant significant comments, and the final applicability 

criteria. We also provide our rationale for finalizing 

applicability criteria based strictly on design and permit 

restrictions rather than actual operating characteristics. 

Finally, we explain why the proposed percentage electric sales 

and natural gas-use applicability criteria are being finalized

instead as criteria to distinguish between separate

subcategories of stationary combustion turbines.

1. Proposed Applicability Criteria

In the January 2014 proposal, we proposed several

applicability criteria for stationary combustion turbines. 

Specifically, to be subject to the proposed emission standards, 
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we proposed that a unit must (1) be capable of combusting more 

than 73 MW (250 MMBtu/h) heat input of fossil fuel; (2) be 

constructed for the purpose of supplying and actually supply 

more than one-third of its potential electric output capacity to 

a utility power distribution system for sale (that is, to the 

grid) on a 3-year rolling average; (3) be constructed for the 

purpose of supplying and actually supply more than 219,000 MWh 

net-electric output to the grid on a 3-year rolling average; (4) 

combust over 10 percent fossil fuel on a 3-year rolling average; 

and (5) combust over 90 percent natural gas on a 3-year rolling 

average. We proposed exempting municipal solid waste combustors 

and commercial and industrial solid waste incinerators. 

Under these proposed applicability criteria, two types of 

stationary combustion turbines that are currently subject to 

criteria pollutant standards under subpart KKKK would not have 

been subject to CO2 standards. The first type was stationary 

combustion turbines that are constructed for the purpose of 

selling and that actually sell one-third or less of their 

potential output or 219,000 MWh or less to the grid on a 3-year 

rolling average basis (i.e., non-base load units). The second 

type was combustion turbines that actually combust 90 percent or 

less natural gas on a 3-year rolling average basis (i.e., multifuel-fired units). 
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We proposed the electric sales criteria in part because 

they already exist in other regulatory contexts (e.g., the coalfired EGU criteria pollutant NSPS) and would promote consistency 

between regulations. Our understanding at proposal was that the 

percentage electric sales criterion would distinguish between 

non-base load units (e.g., low capital cost, flexible, but 

relatively inefficient simple cycle units) and base load units

(i.e., higher capital cost, less flexible, but relatively 

efficient combined cycle units).

While the proposed applicability criteria did not 

explicitly exempt simple cycle combustion turbines from the 

emission standards, we concluded that, as a practical matter,

the vast majority of simple cycle turbines would be excluded

because they historically have operated as peaking units and, on 

average, have sold less than five percent of their potential 

electric output on an annual basis, well below the proposed onethird electric sales threshold.

a. Solicitation of comment on applicability, generally

We solicited comment on a range of issues related to 

applicability. In conjunction with the proposed one-third (i.e., 

33.3 percent) electric sales threshold, we solicited comment on 

a threshold between 20 to 40 percent of potential electric 

output. We also solicited comment on a variable percentage 

electric sales criterion, which would allow more efficient, 
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lower emitting turbines to run for longer periods of operation 

before becoming subject to the standards of performance. Under 

this “sliding scale” approach, the percentage electric sales 

criterion would be based on the net design efficiency of the 

combustion turbine being installed. In this way, more efficient 

combustion turbines would be able to sell a greater portion of 

their potential electric output compared with less efficient 

combustion turbines before becoming subject to an emission

standard. This approach had the benefit of incentivizing the 

development and installation of more efficient simple cycle 

combustion turbines to serve peak load. 

We also solicited comment on whether the percentage

electric sales criterion for stationary combustion turbines 

should be defined on a single calendar year basis. In addition, 

we solicited comment on eliminating the 219,000 MWh aspect of 

the total electric sales criterion to eliminate any incentive 

for generators to install multiple, small, less-efficient 

stationary combustion turbines that would be exempt due to their 

lower output. We further solicited comment on whether to provide 

an explicit exemption for all simple cycle combustion turbines 

regardless of the amount of electricity sold. We additionally

solicited comment on how to implement the proposed electric 

sales, fossil fuel-use, and natural gas-use criteria given that 

they were to be evaluated as 3-year rolling averages during the 
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first three years of operation, and we requested comment on 

appropriate monitoring, recordkeeping, and reporting 

requirements. We specifically solicited comment on whether these 

proposed requirements raised implementation issues because they 

were based on source operation after construction has occurred.

We also solicited comment on excluding electricity sold 

during system emergencies from the calculation of percentage

electric sales. The rationale for this exclusion was that simple 

cycle combustion turbines intended only for peaking applications 

might be required to operate above the proposed percentage

electric sales threshold if a major power plant or transmission 

line became unexpectedly unavailable for an extended period of 

time. The EPA proposed that this flexibility would be

appropriate if the unit were called upon to run after all other 

available generating assets were already running at full load. 

b. Solicitation of comment on broad applicability approach

In both the January 2014 proposal for newly constructed 

EGUs and the June 2014 proposal for modified and reconstructed 

EGUs, the EPA solicited comment on finalizing a broad 

applicability approach instead of the proposed approach. Under 

the proposed approach, a stationary combustion turbine could be 

an affected EGU one year, but not the next, depending on the 

unit’s actual electric sales and the composition of fuel burned. 

The broad applicability approach is consistent with historical 
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NSPS applicability approaches that are based on design criteria 

and include different emission standards for subcategories that 

are distinguished by operating characteristics. Specifically, we 

solicited comment on whether we should completely remove the 

electric sales and natural gas-use criteria from the general 

applicability framework. Instead, the percentage electric sales 

and natural gas-use thresholds would serve as subcategorization 

criteria for distinguishing among classes of EGUs and 

subcategory-specific emissions standards. Under this broad 

applicability approach, the “constructed for the purpose of”

component of the percentage electric sales criterion would be 

completely eliminated so that applicability for combustion 

turbines would be determined only by a unit’s base load rating 

(i.e., greater than 260 GJ/h (250 MMBtu/h)) and its capability 

to sell power to a utility distribution system (i.e., serving a 

generator capable of selling more than 25 MW). In contrast to 

the proposed applicability criteria, under the broad 

applicability approach, non-base load (e.g., simple cycle) and 

multi-fuel-fired (e.g., oil-fired) combustion turbines would 

remain subject to the rule regardless of their electric sales or 

fuel use. We solicited comment on all aspects of this "broad 

applicability approach," including the extent to which it would 

achieve our policy objective of assuring that owners and 
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operators install NGCC combustion turbines if they plan to sell 

more than the specified electric sales threshold to the grid.

2. Comments on Applicability

This section summarizes the comments we received specific 

to each of the proposed applicability criteria. We also received 

more general comments on the scope of the proposed framework as 

compared to the scope of the broad applicability approach.

Comments on applicability for dedicated non-fossil and CHP units 

are discussed in Section III.

a. Base load rating criterion

Many commenters supported a base load rating of 260 GJ/h 

(250 MMBtu/h) because it is generally consistent with the 

threshold used in states participating in the Regional 

Greenhouse Gas Initiative (RGGI) and under Title IV programs. 

Other commenters opposed the proposed applicability thresholds

and stated that all new, modified, and reconstructed units that 

sell electricity to the grid, including small EGUs and simple 

cycle combustion turbines, should be affected EGUs because they 

would otherwise have a competitive advantage in energy markets 

as they would not be required to internalize the costs of 

compliance.

b. Total electric sales criterion

Commenters noted that the 219,000 MWh total electric sales 

threshold put larger combustion turbines at a competitive 
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disadvantage by distorting the market and could have the 

perverse impact of increasing CO2 emissions. These commenters 

noted that the 219,000 MWh total electric sales threshold would 

allow combustion turbines smaller than approximately 80 MW to 

sell more than one-third of their potential electric output, but 

larger, more efficient combustion turbines would still be 

restricted to selling one-third of their potential electric 

output to avoid triggering the NSPS. They argued that this would 

result in a regulatory incentive for generators to install 

multiple, less-efficient combustion turbines instead of fewer, 

more-efficient combustion turbines and could have the unintended 

consequence of increasing CO2 emissions.

c. Percentage electric sales criterion

Commenters from the power sector generally supported a 

complete exemption for simple cycle turbines. These commenters 

stated that simple cycle turbines are uniquely capable of 

achieving the ramp rates (the rate at which a power plant can 

increase or decrease output) necessary to respond to emergency 

conditions and hourly variations in output from intermittent 

renewables. Commenters noted that simple cycle combustion 

turbines serve a different purpose than NGCC power blocks. In 

addition, commenters noted that electricity generation dispatch 

is based on the incremental cost to generate electricity and 

that because NGCC units have a lower incremental generation cost 
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than simple cycle units, economics will drive the use of NGCC

technologies over simple cycle units. However, commenters also 

stated that historic simple cycle operating data may not be 

representative of future system requirements as coal units 

retire, generation from intermittent renewable generation 

increases, and numerous market and regulatory drivers impact 

plant operations. In the absence of a complete exemption, these 

commenters supported a percentage electric sales threshold 

between 40 to 60 percent of a unit’s potential electric output.

Some commenters said that because the proposed percentage

electric sales criterion applied over a three-year period, it 

would adversely affect grid reliability because operators 

conservatively would hedge short-term operating decisions to 

ensure that they have sufficient capacity to respond to 

unexpected scenarios during future compliance periods when the 

demand for electricity is higher. These commenters were 

concerned that such compliance decisions would drive up the cost 

of electricity as the most efficient new units are taken out of 

service to avoid triggering the NSPS and older, less efficient 

units with no capacity factor limitations are ramped up instead.

Some commenters supported the sliding-scale approach (i.e.,

a percentage electric sales threshold based on the design 

efficiency of the combustion turbine) and stated that incentives 

for manufacturers to develop (and end users to purchase) higher 
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efficiency combustion turbines could help mitigate concerns 

about a monolithic national constraint on simple cycle capacity 

factors.

In contrast, others commented that fast-start NGCC units 

intended for peaking and intermediate load applications can 

achieve comparable ramp rates to simple cycle combustion 

turbines, but with lower CO2 emission rates. These commenters 

said that simple cycle turbines should be restricted to their 

historical role as true peaking units and that the proposed onethird electric sales threshold provided sufficient flexibility. 

Some commenters suggested that the one-third electric sales 

threshold could be reduced to 20 percent or lower without 

adverse impacts on grid reliability. 

Commenters noted that a complete exclusion for simple cycle 

turbines would create a regulatory incentive for generators to 

install and operate less efficient unaffected units instead of

more efficient affected units, thereby increasing CO2 emissions.

According to these commenters, any applicability distinctions 

should be based on utilization and function rather than purpose 

or technology. 

Commenters in general supported the use of 3-year rolling 

averages instead of a single-year average for the percentage and 

total electric sales criteria because, in their view, the 3-year 

rolling averages would provide a better overall picture of 
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normal operations. Some commenters stated that a rolling 12-

month or calendar-year average could be severely skewed in a 

given year because of unforeseen or unpredicted events. They 

said that using a 3-year averaging methodology would provide

system operators with needed flexibility to dispatch simple 

cycle units at higher than normal capacity factors. In contrast, 

some commenters stated that, because capacity is forward-looking

(e.g., payments for capacity are often made several years in 

advance), the 3-year averaging period provides limited benefit

because owner/operators need to reserve the ability to respond 

to unforeseen events. 

Commenters noted that potential compliance issues could 

result from the inconsistent time frame between the 3-calendaryear applicability period and the 12-operating-month compliance 

period. For example, a facility could sell more than one-third 

of its potential electric output over a 3-year period, but sell 

less than one-third of its potential electric output during any 

given 12-operating-month compliance period within that 3-year 

period. During a 12-operating-month period with electric sales 

of less than one-third of potential electric output, a unit 

could be operating for long periods at part load and have 

multiple starts and stops. These operating conditions have the 

potential to increase CO2 emissions, regardless of the deign 
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efficiency of the turbine. Therefore, a unit could have an

emission rate in excess of the proposed standard.

Regarding the relationship between the percentage electric 

sales criterion and system emergencies, multiple commenters 

supported exclusion of electricity generated as a result of a 

system emergency from counting towards net sales. These 

commenters stated that the exclusion was appropriate because the 

benefits of operating these units to generate electrical power 

during emergency conditions would outweigh any adverse impacts 

from short-term increases in CO2 emissions. One commenter stated 

that, in addition to declared grid emergencies, other 

circumstances might warrant emergency exemption under the rule, 

including extreme market conditions, limitations on fuel supply, 

and reliability responses.

Multiple commenters opposed the exclusion of system

emergencies when calculating a source's percentage electric

sales for applicability purposes because NSPS must apply 

continuously, even during system emergencies. These commenters 

stated that the EPA does not have the authority under the CAA to 

suspend the applicability of a standard during periods of system

emergency. Some commenters stated that an exclusion would be

unnecessary because the EPA Assistant Administrator for 

Enforcement has the authority to advise a source that the 

government will not sue the source for taking certain actions 
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during an emergency. Commenters said that this enforcement 

discretion approach has provided prompt, flexible relief that is 

tailored to the needs of the particular emergency and the 

communities being served and is only utilized where the relief 

will address the particular emergency at hand. 

Commenters added that this enforcement discretion approach 

is consistent with the CAA’s mandate that emission limits apply 

continuously and provide safeguards against abuse. One commenter 

stated that emergencies happen rarely and typically last for 

short periods, that the proposed percentage electric sales

threshold would allow a source to operate at its full rated 

capacity for up to 2,920 hours per year without triggering 

applicability, and that the potential occurrence of grid 

emergencies would represent a tiny fraction of this time. 

Another commenter stated that no emergency short of large scale 

destruction of power generating capacity by terrorism, war, 

accident, or natural disaster could justify operating a peaking 

unit above a 10-percent capacity factor on a 3-year rolling 

average. 

d. Broad applicability approach

In response to the EPA's request for comments on whether 

the proposed applicability requirements that retrospectively 

look back at actual events (i.e., the electric sales and fuel 

use criteria) would create implementation issues, several 
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permitting authorities opposed the provisions because units 

could be subject to coverage one year but not the next,

resulting in compliance issues and difficulties in determining 

proper pre-construction and operating permit conditions. These 

permitting authorities suggested that in order for a source to 

avoid applicability, the source should be subject to a federally 

enforceable permit condition with associated monitoring, 

recordkeeping, and reporting conditions for assessing 

applicability on an ongoing basis. Other commenters stated that 

an applicability test that concludes after construction and 

operation have commenced is inconsistent with the general 

purpose of an applicability test—to provide clear and 

predictable standards of performance for new sources that would 

apply when they begin operations.

Some commenters opposed the proposed retrospective 

applicability criteria related to actual output supplied during 

a preceding compliance period because EGUs must know what 

performance standards will apply to them during the licensing 

process, and such criteria do not allow the permitting authority 

and the public to know in advance whether an emission standard 

applies to a proposed new unit. Other commenters said that EGUs 

undergoing permitting should be allowed to request limits in 

their operating permit conditions in order to remain below the 

applicability thresholds, as this methodology is consistent with 
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the pre-construction permitting requirements in many federally 

approved SIPs and the current approach under the Title V 

permitting program. 

Many commenters stated a preference for the "proposed 

applicability approach" over the "broad applicability approach." 

These commenters did not think it was necessary to require nonbase load or multi-fuel-fired combustion turbines to be subject 

to emission standards. They stated that there is no 

justification for imposing burdensome monitoring, reporting, and 

recordkeeping requirements that would have no environmental 

benefit (i.e., would not reduce CO2 emissions) because these 

units would be subject to "no emissions standards." Other 

commenters supported the broad applicability approach and stated 

that all new, modified, and reconstructed units that sell 

electricity to the grid, including small EGUs, oil-fired 

combustion turbines, and simple cycle combustion turbines should 

be affected EGUs because they would otherwise have a competitive 

advantage in energy markets as they would not be required to 

internalize the costs of compliance. 

In contrast, to preserve the discretion of state planners 

under section 111(d), many other commenters supported the broad 

applicability approach and the inclusion of new simple cycle 

units within the scope of the section 111(b) emission standards

so that similar, existing simple cycle units could be subject to 
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the 111(d) standards. Numerous other commenters stated that all 

units that sell electricity to the grid should be subject to a

standard, including simple cycle units, because they view the 

utility grid as a single integrated system and that doing so may 

simplify development of future frameworks for cost-effective 

carbon reductions from existing units, such as frameworks based 

on system-wide approaches.

3. Final Applicability Criteria and Rationale

Based on our consideration of the comments received related 

to the proposed applicability criteria and practical 

implementation issues, we are revising how those criteria will 

be implemented. The final applicability criteria for combustion 

turbines are generally consistent with the broad applicability 

approach on which we solicited comment. Section VIII of this 

preamble presents each proposed applicability criterion together 

with the form of the criterion in the final rule. The final 

general applicability framework includes the proposed criteria 

based on the combustion turbine's base load rating and the 

combustion turbine's total electric sales capacity. The final 

general applicability framework also includes multiple

exemptions that are relevant to combustion turbines: combustion 

turbines that are not connected to natural gas pipelines; CHP 

facilities with federally enforceable limits on total electric 

sales; dedicated non-fossil units with a federally enforceable 
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limits on the use of fossil fuels; and municipal waste 

combustors and incineration units. 

The final applicability framework reflects multiple

variations from the proposal that are responsive to public 

comments. First, consistent with the broad applicability 

approach, we are finalizing the percentage electric sales and 

natural gas-use thresholds as subcategorization criteria instead 

of as applicability criteria. In addition, for non-CHP 

combustion turbines, we are eliminating the proposed 219,000 MWh 

total electric sales criterion. Finally, we are eliminating the 

proposed “constructed for the purpose of” qualifier for the 

total and percentage electric sales criteria. We are also not 

finalizing CO2 standards for dedicated non-fossil fuel-fired or 

industrial CHP combustion turbines. The rationale for not 

finalizing CO2 standards for dedicated non-fossil and industrial 

CHP units is discussed in more detail in Section III.

The EPA agrees with commenters that the NSPS applicability 

framework should be structured so that permitting authorities,

the regulated community, and the public can determine what 

standards apply prior to a unit having commenced construction. 

With this in mind, the EPA has concluded that the proposed 

fossil fuel-use, natural gas-use, percentage electric sales, and 

total electric sales applicability criteria for combustion 

turbines are not ideal approaches. Because applicability 
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determinations based on these criteria could change from year to 

year (i.e., units could move in and out of coverage each year

depending on actual operating parameters), some operators would 

not know the extent of their compliance obligations until after 

the compliance period.

Further, from a practical implementation standpoint,

existing permitting rules generally require pre-construction 

permitting authorities to include enforceable conditions 

limiting operations such that unaffected units will not trigger 

applicability thresholds. Such conditions are often called 

“avoidance” or “synthetic minor” conditions, and these 

conditions typically include ongoing monitoring, recordkeeping, 

and reporting requirements to ensure that operations remain 

below a particular regulatory threshold.

The following sections provide further discussion of the 

final general applicability criteria and the rationale for 

changing certain proposed applicability criteria to

subcategorization criteria.

a. Base load rating criterion

We are retaining the applicability criterion that a 

combustion turbine must be capable of combusting more than 260 

GJ/h (250 MMBtu/h) heat input of fossil fuel. We revised the 

proposed 73 MW form of the base load rating criterion to 260 

GJ/h because some commenters misinterpreted the 73 MW form 
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(which is mathematically equivalent to 250 MMBtu/h) as the 

electrical output rating of the generator. This change is a nonsubstantive unit conversion intended to limit misinterpretation. 

While some commenters suggested that we expand this

applicability criterion to cover smaller EGUs as well, we did 

not propose to cover smaller units. Because smaller units emit 

relatively few CO2 emissions compared to larger units and because 

we currently do not have enough information to identify an 

appropriate BSER for these units, we are not finalizing CO2

standards for smaller units. 

b. Total electric sales criterion

The proposed 219,000 MWh total annual sales criterion was 

based on a 25 MW unit operating at base load the entire year 

(i.e., 25 MW * 8,760 h/y = 219,000 MWh/y). This criterion was 

included in the original subpart Da coal-fired EGU criteria 

pollutant NSPS. Coal-fired EGUs tend to be much larger than 25 

MW, and the criterion’s primary purpose was to exempt industrial 

CHP facilities from the criteria pollutant NSPS. In the context 

of combustion turbines, however, commenters expressed concerns 

that the 219,000 MWh electric sales threshold would actually 

encourage owners and operators to install multiple, smaller,

less-efficient simple cycle combustion turbines instead of a 

single, larger, more-efficient simple cycle turbine. The reason 

for this is that the 219,000 MWh threshold would allow smaller 
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simple cycle combustion turbines of less than 80 MW to sell 

significantly more electricity relative to their potential 

electric output than larger turbines. Many commenters also 

indicated that having the flexibility to operate a simple cycle

turbine at a higher capacity factor is important because it 

allows for capacity payments from the transmission authority. In 

light of these comments, we are not finalizing the 219,000 MWh 

total electric sales criterion for non-CHP combustion turbines.

Instead, we are finalizing a criterion that will exempt 

combustion turbines that do not have the ability to sell at 

least 25 MW to the grid. This approach will maintain our goal of 

exempting smaller EGUs, while avoiding the perverse 

environmental incentives mentioned by the commenters. As 

explained in Section III, however, industrial CHP units are 

sized based on demand for useful thermal output, so there is 

less of an incentive for owners and operators to install 

multiple smaller units. Therefore, we are maintaining the 

219,000 MWh total electric sales criterion for CHP units.

c. Percentage electric sales criterion

Commenters generally opposed the proposed percentage

electric sales criterion approach because it was based in part 

on actual electric sales, meaning applicability could change 

periodically (i.e., a unit’s electric sales may change over 

time, rising above and falling below the electric sales 
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threshold). The EPA agrees this situation is not ideal. To avoid 

situations in which applicability changes from year to year, we 

first considered two approaches using permit restrictions. Under 

the first approach, a standard would apply to all sources with 

permit restrictions mandating electric sales above a threshold

(i.e., an approach that closely mirrors the proposed percentage 

electric sales criterion). Under the second approach, a standard 

would apply to all sources without permit restrictions limiting 

electric sales to a level below that threshold (i.e., 

effectively identifying non-base load units and excluding them 

from applicability). As stated in the proposal, we did not think 

it was critical to include peaking and cycling units because 

peaking turbines operate less and because it would be much more 

expensive to lower their emission profile to that of a combined 

cycle power plant or a coal-fired plant with CCS.

The first approach is not practical, however, because new 

combustion turbines could avoid applicability by simply not 

having a permit restriction at all. Moreover, even if a 

combustion turbine were subject to the restriction, it could 

violate its permit if it did not operate enough to sell the 

requisite amount of electricity. This would be nonsensical, 

especially because system demand would not always be sufficient 

to allow all permitted units to operate above the threshold. 

Therefore, we rejected the first permitting approach.
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In contrast, the second approach would be a viable method 

for identifying and exempting peaking units from applicability.

However, there are multiple drawbacks to such an applicability 

approach. First, this approach would subject those turbines

without a permit restricting electric sales to the final 

emission standards, which raises concerns as to whether turbines 

with lower actual sales could achieve the standards. For 

example, new NGCC units tend to dispatch prior to older existing 

units and will generally operate for extended periods of time 

near full load and sell electricity above the percentage 

electric sales threshold. However, as NGCC units age, they tend 

to start and stop more frequently and operate at part load. Yet, 

even if these units sell below the percentage electric sales 

threshold, they would still be affected units if they did not 

take a permit restriction. As commenters noted, part-load 

operation and frequent starts and stops can reduce the 

efficiency of a combustion turbine. While we are confident that 

our final standards for natural gas-fired base load combustion 

turbines can be achieved by units serving either base or 

intermediate load, we are not as confident that affected NGCC 

units that might someday be operated as non-base load units 

(e.g., as NSPS units age their incremental generating costs will 

tend to be higher than newer units and they will dispatch less) 

could achieve the standards.
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More importantly, however, we are concerned that using a 

permitting approach for the percentage electric sales criterion 

would create problems due to the interaction between 111(b) and 

111(d). Under the second permitting approach we considered, 

units with low electric sales would be excluded from 

applicability, while units with high electric sales would be 

included. While these low-electric sales units would generally 

be simple cycle combustion turbines and the high-electric sales 

units would generally be NGCC combustion turbines, this would 

not always be the case. In contrast, we are finalizing an 

applicability approach in the 111(d) emission guidelines that is 

based on a combustion turbine’s design characteristics rather 

than electric sales. Simple cycle combustion turbines are 

excluded from applicability, while NGCC units are included. As a 

result, the universe of sources covered by the 111(b) standards 

would not necessarily be the same universe of sources covered by 

the 111(d) standards. 

To resolve this issue, we considered whether we could 

change the 111(d) applicability criteria to be based on 

historical operation rather than design characteristics. For 

example, if an existing combustion turbine had historically sold 

less than one-third of its potential output to the grid, then it 

would be exempt from the emission guidelines. However, many 

existing NGCC units have historically sold less than this amount 
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of electricity, meaning that they would not be subject to the 

rule. We ran into similar issues when considering other 

thresholds. For example, a percentage electric sales threshold

of 10 percent would still exempt roughly 5 percent of existing 

NGCC units from 111(d), while simultaneously raising 

achievability concerns with the 111(b) standard. Moreover, even 

if we had finalized 111(d) applicability criteria based on 

historical operations, existing NGCC units could have decided to 

take a permit restriction limiting their electric sales going 

forward to avoid applicability. Under any of these scenarios, 

our goals with respect to 111(d) would not be accomplished.

To avoid this result, the EPA has concluded that it is 

appropriate to finalize the broad applicability approach and set 

standards for combustion turbines regardless of what percentage 

of their potential electric output they sell to the grid. To 

accommodate the continued use of simple cycle and fast-start 

NGCC combustion turbines for peaking and cycling applications, 

however, the EPA has subcategorized natural gas-fired combustion 

turbines based on a variation of the proposed percentage 

electric sales criterion. Specifically, and as explained in more 

detail in Section IX.B.2, we are finalizing the sliding-scale 

approach on which we solicited comment. 
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d. Natural gas-use criterion

Similar to the proposed electric sales criteria, commenters 

generally opposed the proposed natural gas-use criterion being 

based on actual operating parameters. As with the electric sales 

criteria, the EPA agrees that applicability that can switch 

periodically due to operating parameters is not ideal. The EPA 

evaluated two approaches for implementing the intent of the 

proposed natural gas-use criterion (i.e., to exclude non-natural 

gas-fired combustion turbines) through operating permit 

restrictions. Under the first approach, an emission standard 

would apply to all combustion turbines with a permit restriction 

mandating that natural gas contribute over 90 percent of total 

heat input.

559 Under the second approach, an emission standard 

would apply to all combustion turbines without a permit 

restriction limiting natural gas use to 90 percent or less of 

total heat input.

560 As with the percentage electric sales

criterion, the first approach is not practical because 

 

559 This approach could also be written as “an emission standard 

would apply to all combustion turbines with a permit restriction 

limiting the use of non-natural gas fuels to 10 percent or less 

of the total heat input.” Applicability could then be avoided by 

simply being permitted to burn non-natural gas fuels for more 

than 876 hours per year even if they actually intended to 

seldom, if ever, combust the alternate fuels.

560 This approach could also be written as “an emission standard 

would apply to all combustion turbines without permit 

restrictions mandating that non-natural gas use contribute over 

10 percent or more of total heat input.”
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combustion turbines could avoid applicability by simply not 

having a permit that requires the use of more than 90 percent 

natural gas, even if they intend to only burn natural gas. We 

disregarded this approach because it would essentially provide a 

pathway for all NGCC units to avoid applicability under both 

111(b) and 111(d). The second approach is problematic because

operating permit restrictions to improve air quality are 

typically written to limit high emission activities (e.g., 

limiting the use of distillate oil to 500 hours annually), not 

to limit lower emitting activities. This approach could lead to 

perverse environmental impacts by incentivizing the use of nonnatural gas fuels, which would typically result in higher CO2

emissions. Furthermore, the second approach would not limit the 

fuels that can be burned by affected units (i.e., combustion 

turbines not required to use non-natural gas fuels) and would 

continue to cover combustion turbines even when they burn over 

10 percent non–natural gas fuels. Because all non-natural gas 

fuels except H2 have CO2 emission rates higher than natural gas,

this approach would exacerbate the concerns raised by commenters 

about the achievability of the 111(b) requirements when burning 

backup fuels.

In light of these issues, the EPA has concluded that permit 

restrictions are not an ideal approach to distinguishing between 

natural gas-fired and multi-fuel-fired combustion turbines and
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are finalizing a variation of the broad applicability approach.

The EPA has concluded that the only practical approach to 

implement the natural gas-use criterion is to look at the 

turbine’s physical ability to burn natural gas. Therefore, we 

are not finalizing CO2 standards for combustion turbines that are 

not capable of firing any natural gas (i.e., not connected to a 

natural gas pipeline). From a practical standpoint, the burners 

of most combustion turbines can be modified to burn natural gas,

so this exemption is essentially limited to combustion turbines 

that are built in remote or offshore locations without access to 

natural gas. Consistent with the broad applicability approach, 

we are finalizing standards for all other combustion turbines, 

but are subcategorizing between natural gas-fired turbines and 

multi-fuel-fired turbines. Specifically, and as explained in 

more detail in Section IX.B.3, we are distinguishing between 

these classes of turbines based on whether they burn greater 

than 90 percent natural gas or not. 

B. Subcategories

We are finalizing a variation of the broad applicability 

approach for combustion turbines where the percentage electric 

sales and natural gas-use criteria serve as thresholds that 

distinguish between three subcategories. These subcategories are 

base load natural gas-fired units, non-base load natural gas-
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fired units, and multi-fuel-fired units. Under the final 

subcategorization approach, multi-fuel-fired combustion turbines 

are distinguished from natural gas-fired turbines if fuels other 

than natural gas (e.g., distillate oil) supply 10 percent or 

more of heat input. Natural gas-fired turbines are further 

subcategorized as base load or non-base load units based on the 

percentage electric sales criterion. The percentage electric 

sales threshold that distinguishes base load and non-base load 

units is based on the specific turbine’s design efficiency 

(i.e., the sliding-scale approach). The percentage electric 

sales threshold is capped at 50 percent.

This section describes comments we received regarding the 

proposed size-based subcategories and our rationale for not 

finalizing them. In addition, it describes comments we received 

regarding sales-based subcategories and our rationale for 

adopting the sliding scale to distinguish between subcategories.

Finally, it describes comments we received regarding fuel-based 

subcategories and our rationale for adopting fuel-based 

subcategories.

1. Size-based Subcategories

At proposal, the EPA identified two size-based 

subcategories: (1) large natural gas-fired stationary combustion 

turbines with a base load rating greater than 850 MMBtu/h and 

(2) small natural gas-fired stationary combustion turbines with 
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a base load rating of 850 MMBtu/h or less. The EPA received 

numerous comments regarding our proposal to subcategorize

combustion turbines by size. Some commenters agreed with the 850 

MMBtu/h cut-point between large and small units, some suggested 

increasing it to 1,500 MMBtu/h, and others suggested eliminating 

size-based subcategorization altogether. For example, some

commenters stated that the 850 MMBtu/h cut-point was

inappropriate because it was originally calculated based on NOX

performance, not CO2 performance. These commenters stated that 

850 MMBtu/h was not a logical demarcation between more efficient 

and less efficient combustion turbines, but rather would divide 

the units into arbitrary size classifications. These commenters 

suggested that 1,500 MMBtu/h would be a better cut-point because

data reported to Gas Turbine World (GTW) showed that new 

combustion turbines are not currently offered with a heat input 

rating between 1,300 MMBtu/h and 1,800 MMBtu/h, so the higher

cut-point would more accurately reflects when more efficient 

technologies are available.

In contrast, other commenters said that differentiation 

between small and large combustion turbines was not justified at 

all because many of the same efficiency technologies that reduce 

the emission rates of larger units could be incorporated into 

smaller units (e.g., upgrades that increase the turbine engine 

operating temperature, increase the turbine engine pressure 
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ratio, or add multi-pressure steam and a steam reheat cycle). 

These commenters also said that separate standards for small and 

large turbines would undermine the incentive for technology 

innovation, which they described as a key purpose of the NSPS 

program, and that relaxing standards for smaller units would

discourage investment in more efficient technologies, resulting 

in increased CO2 emissions. These commenters recommended that the 

limit for both large and small units be no higher than 1,000 

lb CO2/MWh-g.

After evaluating these comments, the EPA has decided not to 

subcategorize combustion turbines based on size for several 

reasons. First, the heat input values listed in Gas Turbine 

World do not include potential heat input from duct burners.562

Because the heat input from duct burners is necessary to 

accurately determine potential electric output, our definition 

of “base load rating” includes the heat input from any installed 

duct burners. The EPA reviewed the heat input data for existing 

NGCC units that has been submitted to CAMD. These data include 

the heat input from duct burners and show that multiple NGCC

power blocks have been built in the past with heat input 

 

562 Duct burners are optional supplemental burners located in the 

HRSG that are used to generate additional steam. Heat input to 

duct burners could in theory be twice that of the combustion 

turbine engine, but are more commonly sized at 10 to 30 percent 

of the heat input to the combustion turbine engine.
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capacities that fall within the range that commenters suggested

new turbines are not offered. Therefore, the EPA has concluded 

that the regulated community uses various sizes of NGCC turbines 

and when the heat input from duct burners is included, there is

no clear break between the NGCC unit sizes that could 

distinguish between small and large units. In fact, 

subcategorizing by size could unduly influence the development 

of future NGCC offerings because manufacturers could be 

incentivized to design new products at the top end of the small 

subcategory to take advantage of the less stringent emission 

standard. 

Second, commenters suggested that a cut-point of 1,500 

MMBtu/h reflects when more efficient technologies become 

available. However, when we reviewed actual operating data and 

design data, we only found a relatively weak correlation between 

turbine size and CO2 emission rates and did not see a dramatic 

drop in CO2 emission rates at 1,500 MMBtu/h. The variability of 

emission rates among similar size units far exceeds any 

difference that could be attributed to a difference in size. In 

addition, the most efficient one-to-one configuration NGCC power 

block with a base load rating of 1,500 MMBtu/h or less has a 

design emission rate of the 767 lb CO2/MWh-n (984 MMBtu/h). The 

most efficient one-to-one configuration NGCC power block with a 

base load rating just greater than 1,500 MMBtu/h has a design 
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emission rate of 772 lb CO2/MWh-n (1,825 MMBtu/h). Because the 

smaller unit has a lower design emission rate than the larger 

unit, increasing the cut-point does not make sense.

Finally, the EPA has concluded that, while certain smaller 

NGCC designs may be less efficient than larger NGCC designs, 

most existing small units have demonstrated emission rates below 

the range of emission rates on which we solicited comment. We 

have concluded that the lower design efficiencies of some small 

NGCC units are primarily related to model-specific design 

choices in both the turbine engine and HRSG, not an inherent 

limitation in the ability of small NGCC units to have comparable 

efficiencies to large NGCC units. Specifically, manufacturers

could improve the efficiency of the turbine engine by using 

turbine engines with higher firing temperatures and high 

compression ratios and could improve the efficiency of the steam 

cycle by switching from single or double-pressure steam to 

triple-pressure steam and adding a reheat cycle. For all of 

these reasons, we have decided against subcategorizing 

combustion turbines based on size. Our rationale for setting a 

single standard for small and large combustion turbines is 

explained in more detail in Section IX.D.3.a below.

2. Sales-based Subcategories

As described above in Section IX.A.3.c, the final 

applicability criteria do not include an exemption for non-CHP 
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units based on actual electric sales or permit restrictions 

limiting the amount of electricity that can be sold. Instead, we 

are finalizing the percentage electric sales criterion as a 

threshold to distinguish between two natural gas-fired 

combustion turbine subcategories. The industry uses a number of 

terms to describe combustion turbines with different operating 

characteristics based on electric sales (e.g., capacity 

factors). Combustion turbines that operate at near-steady, high 

loads are generally referred to as "base load" or “intermediate 

load” units, depending on how many hours the units operate 

annually. Combustion turbines that operate continuously with 

variable loads that correspond to variable demand are referred 

to as "load following" or "cycling" units. Combustion turbines 

that only operate during periods with the highest electricity 

demand are referred to as "peaking" units. However, it is 

difficult to characterize a particular unit using just one of 

these terms. For example, a particular unit may serve as a load 

following unit during winter, but serve as a base load unit 

during summer. In addition, none of these terms has a precise 

universal definition. In this preamble, we refer to the 

subcategory of combustion turbines that sell a significant 

portion of their potential electric output as "base load units." 

This subcategory includes units that would colloquially be 

referred to as base load units, as well as some intermediate
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load and load following units. We refer to all other units as 

“non-base load units.” This subcategory includes peaking units, 

as well as some load following and intermediate load units. The 

threshold that distinguishes between these two subcategories is 

determined by a unit’s design efficiency and varies from 33 to 

50 percent, hence the term “slide scale” approach. 

Numerous commenters supported three sales-based

subcategories for peaking, intermediate load, and base load 

units. These commenters said that each subcategory should be 

distinguished by annual hours of operation and that each should 

have a different BSER and emission standard. Other commenters 

opposed the tiered approach. These commenters said that separate 

standards for different operating conditions would be 

complicated to implement and enforce, while providing few 

benefits. These commenters said that a tiered approach could 

also have the unintended consequence of encouraging less 

efficient technologies because it would create a regulatory 

incentive to install lower-capital-cost, less-efficient units 

that would operate under the percentage electric sales threshold 

instead of higher-capital-cost, more-efficient units that would 

operate above the threshold.

After evaluating these comments, the EPA has concluded that 

it is appropriate to adopt a two-tiered subcategorization

approach based on a percentage electric sales threshold to 
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distinguish between non-base load and base load units. While we 

agree with commenters that separate standards for peaking, 

intermediate, and base load units is attractive on the surface, 

we ultimately concluded that a three-tiered approach is not 

appropriate for several reasons. First, the increased generation 

from renewable sources that is anticipated in the coming years 

makes it very difficult to determine appropriate thresholds to 

distinguish among peaking, intermediate, and base load 

subcategories. Indeed, the boundaries between these demandserving functions may blur or shift in the years to come. The

task is further complicated because each transmission region has 

a different mix of generation technologies and load profiles 

with different peaking, intermediate, and base load 

requirements. 

Second, there are only two distinct combustion turbine 

technologies – simple cycle units and NGCC units. In theory, the 

BSER for the intermediate load subcategory could be based on 

high-efficiency simple cycle units or fast-start NGCC units, but 

these are variations on traditional technologies and not 

necessarily distinct. Moreover, we do not have specific cost 

information on either high-efficiency simple cycle turbines or 

fast-start NGCC units, so our ability to make cost comparisons 

to conventional designs is limited.
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Finally, even if we could identify appropriate sales 

thresholds to distinguish between peaking, intermediate load,

and base load subcategories, we do not have sufficient 

information to establish a meaningful output-based standard for 

an intermediate load subcategory at this time. In the transition 

zone from peaking to base load operation (i.e., cycling and 

intermediate load), combustion turbines may have similar 

electric sales, but very different operating characteristics. 

For example, despite having similar sales, one unit might have 

relatively steady operation for a short period of time, while

another could have variable operation throughout the entire 

year. The latter unit would likely have a higher CO2 emission 

rate. For all of these reasons, the EPA has concluded that we do 

not have sufficient information at this time to establish three 

sales-based subcategories. 

Instead, as we explained above, we are finalizing two 

sales-based subcategories. To determine an appropriate threshold 

to distinguish between base load and non-base load units, the 

EPA considered the important characteristics of the combustion 

turbines that serve each type of demand. For non-base load

units, low capital costs and the ability to start, stop, and 

change load quickly are key. Simple cycle combustion turbines 

meet these criteria and thus serve the bulk of peak demand. In 

contrast, for base load units, efficiency is the key 
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consideration, while capital costs and the ability to start and 

stop quickly are less important. While NGCC units have 

relatively high capital costs and are less flexible 

operationally, they are more efficient than simple cycle units. 

NGCC units recover the exhaust heat from the combustion turbine 

with a HRSG to power a steam turbine, which reduces fuel use and 

CO2 emissions by approximately one-third compared to a simple 

cycle design. Consequently, base load units use NGCC technology. 

Because simple cycle turbines have historically been non-base 

load units, we have concluded that it is appropriate to 

distinguish between the non-base load and base load 

subcategories in a way that recognizes the distinct roles of the

different turbine designs on the market.

The challenge, however, is setting a threshold that will 

not distort the market. The future distinction between non-base 

load and base load units is unclear. For example, some 

commenters indicated that increased generation from intermittent 

renewable sources has created a perceived need for additional 

cycling and load following generation that will operate between 

the traditional roles of peaking and base load units. To fulfill

this perceived need, some manufacturers have developed highefficiency simple cycle turbines. These high-efficiency turbines 

have higher capital costs than traditional simple cycle turbine 

designs, but maintain similar flexibilities, such as the ability 
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to start, stop, and change load rapidly. Other manufacturers 

have developed fast-start NGCC turbines to fill the same role. 

These newer NGCC designs have lower design efficiencies than 

NGCC designs intended to only operate as base load units, but 

are able to start up more quickly to respond to rapid changes in 

electricity demand. As a result of these new technological 

developments, both high-efficiency simple cycle and fast-start 

NGCC units can be used for traditional peaking applications, as 

well as for higher capacity applications, such as supporting the 

growth of intermittent renewable generation. 

With the changing electric sector in mind, we set out to 

identify an appropriate percentage electric sales threshold to 

distinguish between non-base load and base load natural gasfired units. Two factors were of primary importance to our 

decision. First, the threshold needed to be high enough to 

address commenters’ concerns about the need to maintain 

flexibility for simple cycle units to support the growth of 

intermittent renewable generation. Second, the threshold needed

to be low enough to avoid creating a perverse incentive for 

owners and operators to avoid the base load subcategory by 

installing multiple, less efficient turbines instead of fewer, 

more efficient turbines.

To determine the potential impact of intermittent renewable 

generation on the operation of simple cycle units, we examined 
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the average electric sales of simple cycle turbines in the lower 

48 states between 2005 and 2014 using information submitted to 

CAMD. We combined this data with information reported to the EIA 

on total in-state electricity generation, including wind and 

solar, from 2008 through 2014. We focused on data from the

Southwest Power Pool (data approximated by EGUs in Nebraska, 

Kansas, and Oklahoma), Texas, and California. All of these 

regions have relatively large amounts of generation from wind 

and solar and experienced increases in the portion of total 

electric generation provided by wind and solar during the 2008-

2014 period.

a. Southwest Power Pool

The portion of in-state generation from wind and solar in 

the Southwest Power Pool increased from 3 to 16 percent between 

2008 and 2014. The average growth rate of wind and solar was 28 

percent, while overall electricity demand grew 1 percent 

annually on average. Based on statements in some of the 

comments, we expected to see a large change in the operation of 

simple cycle turbines in this region. However, the average 

electric sales from simple cycle turbines only increased at an 

annual rate of 1.7 percent, and remained essentially unchanged 

at 3 percent of potential electric output between 2008 and 2014. 

Total generation from simple cycle turbines in the Southwest 

Power Pool increased slightly more, at an annual rate of 2.5 
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percent, which was the result of additional simple cycle 

capacity being added to address increased electricity demand.

This lack of a significant change in the operation of 

simple cycle turbines could be explained by the Southwest Power 

Pool’s relatively large amount of exported power. If most of the 

region’s renewable generation was being exported, the 

intermittent nature of this power would primarily impact other 

transmission regions. An alternate explanation, however, is that 

other generating assets are flexible enough to respond to the 

intermittent nature of wind and solar generation and that simple 

cycle turbines are not necessary to back up these assets to the 

degree some commenters suggested. If this is the case, then new 

simple cycle turbines may primarily continue to fill their 

historical role as peaking units going forward, while other 

technologies, such as fast-start NGCC units, may provide the 

primary backup capacity for new wind and solar.

b. Texas

The portion of in-state generation from wind and solar in 

Texas increased from 4 to 9 percent between 2008 and 2014. The 

average growth rate of wind and solar was 13 percent, while 

overall demand grew at an average rate of 2 percent annually. 

Similar to the Southwest Power Pool, the average electric sales 

of simple cycle turbines has remained relatively unchanged. In 

fact, the average electric sales of these turbines decreased at 
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an annual rate of 1.1 percent. Total generation from simple 

cycle turbines increased at an annual rate of 6.6 percent, 

however, due to simple cycle capacity additions that occurred at 

approximately four times the rate one would expect from the

growth in overall demand.

The most likely technologies to back up intermittent 

renewable generation have low incremental generating costs and 

can start up and stop quickly. Highly efficient simple cycle 

units meet these criteria. As such, the EPA has concluded that 

the most efficient simple cycle turbines in a given region are 

the most likely to support intermittent renewable generation. 

Focusing on these simple cycle turbines will address concerns 

raised by commenters about the future percentage electric sales 

of highly efficient simple cycle turbines and give an indication 

of the impact of increased renewable generation on non-base load 

units intended to backup wind and solar. There are two highly 

efficient intercooled simple cycle turbines installed in Texas. 

These two combustion turbines sell an average of 10 percent of 

their potential electric output annually, compared to an average 

of 3 percent for the remaining simple cycle turbines. No simple 

cycle turbine in Texas sold more than 25 percent of its 

potential electric output annually. The rapid growth in simple 

cycle capacity, but not overall capacity factors, could indicate 

that the additional generation assets are providing firm 
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capacity for intermittent generation sources such as wind and 

solar, but that capacity is infrequently required. Based on the 

data, even highly efficient simple cycle turbines are expected 

to continue sell less than one-third of their potential electric 

output. 

c. California

The portion of in-state generation from wind and solar in 

California increased from 3 to 11 percent between 2008 and 2014. 

The average growth rate of wind and solar was 25 percent, while 

overall demand has remained stable. The operation of simple 

cycle turbines in California has changed more significantly than 

in the other evaluated regions. The average electric sales from 

simple cycle turbines increased from 5.1 to 5.9 percent, an 

annual rate increase of 4.5 percent. As in Texas, considerable 

additional simple cycle capacity has been added in recent years. 

The total capacity of simple cycle turbines is increasing at 15 

percent annually even though overall demand has remained 

relatively steady. In addition, the newest simple cycle turbines 

are operating at higher capacity factors than the existing fleet 

of simple cycle turbines, resulting in an average increase in 

generation from simple cycle turbines of 21 percent. Many of the 

new additions are intercooled simple cycle turbines that may 

have been installed with the specific intent to back up wind and 

solar generation. 
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The average electric sales for the intercooled turbines 

ranged from 3 to 25 percent, with a 7 percent average. No simple 

cycle turbines in California have sold more than one-third of 

their potential electric output on an annual basis. The 

operation of simple cycle turbines that existed prior to 2008 

has not changed significantly. Average electric sales for these 

turbines increased at an annual rate of 0.1 percent. This 

indicates that support for new renewable generation is being 

provided by new units and not by the installed base of simple 

cycle units. These units are still serving their historical role 

of providing power during peak periods of demand. 

Based on our data analysis, the proposed one-third electric 

sales threshold would appear to offer sufficient operational 

flexibility for new simple cycle turbines. Existing NGCC units, 

other generation assets, and demand-response programs are 

currently providing adequate backup to intermittent renewable 

generation. In the future, however, existing NGCC units will 

likely operate at higher capacity factors. They will therefore 

be less available to provide backup power for intermittent 

generation. In addition, the amount of power generated by

intermittent sources is expected to increase in the future. Both 

of these factors could require additional flexibility from the 

remaining generation sources to maintain grid reliability. 
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Even though fast-start NGCC units, reciprocating internal 

combustion engines, energy storage technologies, and demandresponse programs are promising technologies for providing 

backup power for renewable generation, none of them historically 

have been deployed in sufficient capacity to provide the 

potential capacity needed in the future to facilitate the 

continued growth of renewable generation. While we anticipate 

that state and federally issued permits for new electric 

generating sources will consider the CO2 benefits of these 

technologies compared to simple cycle turbines, the EPA has 

concluded at this time that it is appropriate to finalize a 

percentage electric sales threshold that provides additional 

flexibility for simple cycle turbines.

Specifically, we have concluded that a percentage electric 

sales threshold based on a unit’s design net efficiency at 

standard conditions is appropriate. This is the sliding-scale 

approach on which we solicited comment. Several commenters 

supported this approach because it provides sufficient 

operational flexibility for new simple cycle and fast-start NGCC

combustion turbines and simultaneously promotes the installation 

of the most efficient generating technologies. By allowing more 

efficient turbines to sell more electricity before becoming 

subject to the standard for the base load subcategory, the 

sliding scale should reduce the perverse incentive for owners 
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and operators to install more lower-capital-cost, less-efficient 

units instead of fewer higher-capital-cost, more-efficient 

units. At the same time, the sliding scale should incentivize 

turbine manufacturers to design higher efficiency simple cycle 

turbines that owners and operators can run more frequently.

The net design efficiencies for aeroderivative simple cycle 

combustion turbines range from approximately 32 percent for 

smaller designs to 39 percent for the largest intercooled 

designs. The net design efficiencies of industrial frame units 

range from 30 percent for smaller designs to 36 percent for the 

largest designs. These efficiency values follow the methodology 

the EPA has historically used and are based on the higher 

heating value (HHV) of the fuel. In contrast, combustion turbine 

vendors in the U.S. often quote efficiencies based on the lower 

heating value (LHV) of the fuel. The LHV of a fuel is determined 

by subtracting the heat of vaporization of water vapor generated 

during combustion of fuel from the HHV. For natural gas, the LHV 

is approximately 10 percent lower than the HHV. Therefore, the 

corresponding LHV efficiency ranges would be 35 to 44 percent 

for aeroderivative designs and 33 to 40 percent for frame 

designs. We considered basing the percentage electric sales 

threshold on both the HHV and LHV. The EPA typically uses the 

HHV, but in light of commenters’ concerns regarding uncertainty 
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in the operation of non-base load units in the future, we opted 

to be conservative and use the LHV efficiency.

We anticipate that high-efficiency simple cycle and faststart NGCC turbines will make up the majority of new capacity

intended for non-base load applications. Based on the slidingscale approach, owners and operators of new simple cycle 

combustion turbines will be able to sell between 35 to 44

percent of the turbine’s potential electric output. Our analysis 

showed that 99.5 percent of existing simple cycle turbines have 

not sold more than one-third of their potential electric output 

on an annual basis. In addition, 99.9 percent of existing simple 

cycle turbines have not sold more than 36 percent of their 

potential electric output on an annual basis. The two simple 

cycle turbines that exceeded the 36 percent threshold had annual 

electric sales of 39 and 45 percent and are located in Montana 

and New York, respectively. As noted earlier, the most efficient 

simple cycle turbine currently available is 44 percent efficient 

and would accommodate the operations at the Montana facility. 

The only existing simple cycle turbine that exceeded the maximum 

allowable percentage electric sales threshold of 44 percent,

which is based on current simple cycle designs, sold an 

abnormally high amount of electricity in 2014. It is possible 

that this unit was operating under emergency conditions. As 

explained below, the incremental generation due to the emergency
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would not have counted against the percentage electric sales 

threshold.

R.

We are capping the percentage electric sales threshold at 

50 percent of potential electric output for multiple reasons. 

First, NGCC emission rates are relatively steady above 50 

percent electric sales, so there is no reason that a NGCC unit 

with sales greater than this amount should not have to comply 

with the output-based standard for the base load subcategory. 

Second, the net design efficiency of the fast-start NGCC units

intended for peaking and intermediate load applications is 49 

percent. As described earlier, this technology can serve the 

same purpose as high-efficiency simple cycle turbines. If we 

were to set a cap any lower than 50 percent, it could create a 

disincentive for owners and operators to choose this promising 

new technology.

Finally, the EPA solicited comment on excluding electricity 

sold during system emergencies from counting towards the

percentage electric sales threshold. After considering the 

comments, we have concluded that this exclusion is necessary to 

provide flexibility, maintain system reliability, and minimize

overall costs to the sector. We disagree with commenters that 

suggested that the EPA’s existing enforcement discretion would

be a viable alternative. An enforcement discretion-based 
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approach would not provide certainty to the regulated community, 

public, and regulatory authorities on the applicability of the 

emission standards, which is a primary reason why we are 

finalizing the broad applicability approach. Moreover, system 

emergencies are defined events, so commenters’ fears that the 

exclusion will be subject to abuse are overstated. Therefore,

electricity sold during hours of operation when a unit is called 

upon to operate due to a system emergency will not be counted 

toward the percentage electric sales threshold. However, 

electricity sold by units that are not called upon to operate 

due to a system emergency (e.g., units already operating when 

the system emergency is declared) will be counted toward the 

percentage electric sales threshold.

In summary, the EPA is finalizing the percentage electric 

sales criterion as a threshold to distinguish between two 

natural gas-fired combustion turbine subcategories. 

Specifically, all units that have electric sales greater than 

their net LHV design efficiencies (as a percentage of potential 

electric output) are base load units. All units that have 

electric sales less than or equal to their net LHV design 

efficiencies are non-base load units. We are capping the 

percentage electric sales threshold at 50 percent of potential 

electric output. This sliding-scale approach will limit the 

operation of the least efficient units, provide flexibility for 
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renewable energy growth, and incentivize the development of more 

efficient simple cycle units.

3. Fuel-based Subcategories

As described in Section IX.A.3.d, we are finalizing a 

version of the broad applicability approach. Under the broad 

applicability approach, the EPA solicited comment on a 

subcategorization approach based in part on natural gas-use. We 

received few comments on this issue. One of the comments we did 

receive was that combustion turbines that burn fuels other than 

natural gas have higher CO2 emissions due to the higher relative 

carbon content of alternate fuels. Besides hydrogen,563 natural 

gas has the lowest CO2 emission rate on a lb/MMBtu basis of any 

fossil fuel. Therefore, burning fuels other than natural gas 

will result in a higher CO2 emission rate. We interpret this 

comment to mean that, if we were to subcategorize based on fuel 

use, turbines that burn non-natural gas fuels should receive a 

less stringent emission standard.

For the reasons described in the applicability section, we 

have decided to set emission standards for all combustion 

turbines capable of burning natural gas, regardless of the 

actual fuel burned, to avoid the practical problems that would 

 

563 Hydrogen would only be considered a fossil fuel if it were 

derived for the purpose of creating useful heat from coal, oil, 

or natural gas.
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have arisen under the proposed approach. However, as commenters

explained, multi-fuel-fired combustion turbines cannot achieve 

the emission standards achieved by natural-gas fired turbines. 

For this reason, it would not be reasonable to require affected 

EGUs to comply with a standard based on the use of natural gas 

during periods when significant quantities of non-natural gas 

fuels are being burned. If we did not subcategorize, owners and 

operators would not be able to combust other fuels in their 

turbines, including process gas, blast furnace gas, and 

petroleum-based liquid wastes, which might otherwise be wasted.

In addition, without the ability to burn backup fuels during 

natural gas curtailments, grid reliability could be jeopardized.

Therefore, we are finalizing a separate fuel-based subcategory 

for multi-fuel-fired combustion turbines. To distinguish between 

this subcategory and the natural gas-fired subcategories, we are 

using the same threshold as proposed. Specifically, combustion 

turbines that burn ninety percent or less natural gas on a 12-

operating-month rolling average basis will be included in this 

subcategory and subject to a separate emission standard, which 

is discussed in Section IX.D.3.d.

C. Identification of the Best System of Emission Reduction

This section summarizes the EPA’s proposed BSER 

determinations for stationary combustion turbines, provides a 

summary of the comments we received, and explains our final BSER 
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determinations for each of the three subcategories we are now 

finalizing. For natural gas-fired stationary combustion turbines 

operating as base load units, we proposed and are finalizing the 

use of NGCC technology as the BSER. For the other two 

subcategories of affected combustion turbines – non-base load 

natural gas-fired combustion turbines and multi-fuel-fired 

combustion turbines – we are finalizing the use of clean fuels

as the BSER. 

1. Proposed BSER

We considered three alternatives in evaluating the BSER for 

base load natural gas-fired combustion turbines: (1) partial 

CCS, (2) high-efficiency simple cycle aeroderivative turbines,

and (3) modern, efficient NGCC turbines. We rejected partial CCS 

as the BSER because we concluded that we did not have sufficient 

information to determine whether implementing CCS for combustion 

turbines was technically feasible. We rejected high-efficiency 

simple cycle aeroderivative turbines as the BSER because this 

standalone technology does not provide emission reductions and 

generally is more expensive than NGCC technology for base load 

applications. In contrast, NGCC is the most common type of new 

fossil fuel-fired EGU currently being planned and built for 

generating base load power. NGCC is technically feasible, and 

NGCC units are currently the lowest-cost, most efficient option 

for new base load fossil fuel-fired power generation. After 
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considering the options, the EPA proposed to find that modern, 

efficient NGCC technology is the BSER for base load natural gasfired combustion turbines. 

For non-base load natural gas-fired units and multi-fuelfired units, we did not propose a specific BSER or associated 

numeric emission standards, but instead solicited comment on 

these issues.

2. Comments on the Proposed BSER for Base Load Natural Gas-Fired 

Combustion Turbines

This section summarizes the differing comments submitted on 

the proposed BSER for base load natural gas-fired combustion 

turbines. Some commenter supported partial CCS as the BSER, 

others supported advanced NGCC designs as the BSER, and others 

supported the proposed BSER.

a. Partial CCS

Some commenters stated that our proposed BSER analysis for 

stationary combustion turbines was inconsistent with our 

proposed BSER analysis for coal-fired units. They stated that 

the EPA had determined that the use of CCS was feasible for 

coal-fired generation based on current CCS projects under 

development at coal-fired generating stations, but did not come 

to the same conclusion for combustion turbines. These commenters 

stated that CO2 removal is just as technologically feasible and 

economically reasonable for a natural gas-fired EGU as for a 
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coal-fired EGU. While some of these commenters wanted the EPA to 

reconsider CCS as the BSER for NGCC, many of these commenters 

were attempting to prove that if the agency did not choose CCS 

as the BSER for NGCC units, then the agency should not for coalfired units either. 

Some commenters referenced the Northeast Energy Association 

NGCC plant in Bellingham, MA, which operated from 1991-2005 with 

85 – 95 percent carbon capture on a 320 MW unit for use in the 

food and beverage industry, that was referred to in the 

proposal. This plant captured 330 tons of CO2 per day from a 40 

MW slip stream and was decommissioned as a result of financial 

difficulties, including rising gas prices and discontinuation of 

tax credits. According to these commenters, this plant provided 

sufficient proof that CCS technology is adequately demonstrated 

for NGCC units. Additionally, these commenters referred to other 

NGCC plants that are planned or in development that will 

incorporate CCS. The plants mentioned were the Sumitomo Chemical 

Plant in Japan, the Peterhead CCS project in Scotland, and the 

GE-Sargas Plant in Texas. The Sumitomo Chemical Plant has a base 

load NGCC unit with CCS operating on an 8 MW slip-stream that 

captures about 150 tons of CO2 per day for commercial use in the 

food and beverage industry. This carbon capture system has been 

operating since 1994. The Peterhead CCS project in Scotland is 

in the planning stages. It is a collaboration between Shell and 
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SSE to provide 320 MW of electricity to its customers from a 

base load NGCC unit with 90 percent carbon capture. The CO2 will 

be transported to the depleted Goldeneye reservoir in the ocean 

where it will be stored and continuously monitored. The GESargas Plant in Texas is a planned joint venture that does not 

currently have a location selected, but is intended to be a base 

load NGCC unit with CCS used for EOR.

These commenters also referenced reports authored by DOE, 

NETL, the Clean Air Task Force (CATF), CCS Task Force, ICF Inc., 

and Global CCS Institute suggesting that, because CCS technology 

for NGCC is included in these reports, it is adequately 

demonstrated. Some commenters referred to a DOE/NETL study that 

suggested that the cost of CCS for NGCC units would be more 

cost-effective than for coal-fired EGUs. One non-industry 

commenter emphasized that a technology does not have to be in 

use to be considered adequately demonstrated. 

In addition, some commenters disagreed with the EPA’s 

decision to treat combustion turbines differently than coalfired units with respect to CCS on the basis that combustion 

turbines start up, shut down, and cycle load more frequently

than coal-fired units. According to these commenters, the

operating characteristics of combustion turbines do fluctuate, 

but so do those of coal-fired units. Another commenter said that 

even if NGCC operations vary more than they do for coal-fired 
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units, it is not an impediment to using CCS because combustion 

turbine operators could bypass the carbon capture system during 

startup and shutdown modes (which are typically shorter and less 

intensive efforts compared to the startup or shutdown of a coal 

facility) and then employ the carbon capture system when 

operating normally. One commenter stated that most future base 

load fossil fuel-fired generation will be NGCC and that not 

making CCS the BSER for NGCC would result in significant CO2

emissions.

Other commenters supported the EPA’s determination that CCS 

is not the BSER for combustion turbines. These commenters said 

that CCS is not adequately demonstrated for combustion turbines 

because none are currently operating, under construction, or in 

the advanced stages of development. They also noted that CCS 

would have to be demonstrated for the range of facilities 

included in the regulated source category, which they alleged 

includes both simple cycle and NGCC units. They specifically 

noted that the Bellingham, MA demonstration facility was not a 

full-scale commercial NGCC power plant operating with CCS. 

These commenters agreed with the EPA that CCS does not 

match well with the operating flexibilities of NGCC and simple 

cycle units. They agreed with the EPA that frequent cycling

restricts the efficacy of CCS on these units, a problem which 

would only get worse as more renewable energy sources are 
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integrated into the grid. These commenters added that NGCC units 

operate differently than coal-fired units because the former

start, stop, and cycle frequently, whereas the latter tend to 

operate at relatively steady loads and do not start and stop 

frequently. They stated that even if technical barriers could be 

overcome, the application of CCS to combustion turbines would be 

more costly (compared to the application of CCS to coal-fired 

units) on a dollars-per-ton basis. In addition, these commenters 

said that other industries’ experience with CCS could not be 

transferred to NGCC units due to differences in flue gas CO2

concentration. 

Some commenters stated that CAA section 111(a) requires the 

EPA to account not only for the cost of achieving emission 

reductions, but also for impacts on energy requirements and the 

environment. The commenters cited to Sierra Club v. Costle, 

where the D.C. Circuit observed that the EPA "must exercise its 

discretion to choose an achievable emission level which 

represents the best balance of economic, environmental, and 

energy considerations."564 The commenters stated that requiring 

CCS on combustion turbines would adversely affect the nation’s 

energy needs and the environment because imposing CCS on 

combustion turbines would invariably delay the emission 

 

564 Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. Cir. 1981).
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reductions that can be obtained from new NGCC projects that 

displace load from older, less efficient generating 

technologies. In addition, the commenters stated that, because

combustion turbines are projected to provide a significant share 

of new power generation, the EPA should recognize that requiring 

CCS on these units would have a disproportionally higher impact 

on electricity prices when compared to the projected number of 

new coal-fired projects. These commenters concluded that the EPA 

could not determine that CCS is the BSER for combustion turbines

without producing severe and unacceptable consequences for the 

availability of affordable electricity in the U.S.

b. NGCC turbines

Some commenters stated that the proposed BSER analysis 

should have reflected the emission rates achieved by the latest 

designs deployed at advanced, state-of-the-art NGCC 

installations. These commenters stated that advanced NGCC 

technologies are the best system for reducing CO2 emissions with 

no negative environmental impacts and no negative economic 

impacts on rate payers. They stated that advanced NGCC 

technologies are capable of achieving emission rates that are 8 

percent lower than conventional NGCC facilities. They also said 

that the majority of existing sources that do not deploy these 

advanced technologies are currently able to meet the standard 

and that the proposal failed to explain why these lower-emitting 
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advanced technologies that are more than adequately demonstrated 

were not selected as the BSER.

c. Simple cycle turbines

Many commenters opposed the EPA’s proposal to set emission 

standards for combustion turbines based on their function rather 

than based on their design. These commenters stated that the 

EPA’s determination that NGCC technology is the BSER for base 

load natural gas-fired combustion turbines would apply equally 

to simple cycle turbines if they sell electricity in excess of 

the percentage electric sales threshold. They pointed to the 

word "achievable" in CAA section 111(a)(1) and stated that 

applying an emission standard based on NGCC technology to simple 

cycle units was legally indefensible because simple cycle units 

cannot achieve emission rates as low as NGCC units. In contrast, 

many other commenters agreed with the EPA’s basic approach and 

stated that NGCC technology should be the BSER for base-load 

functions, while simple cycle technology should be the BSER for 

peak-load functions.

3. Comments on Non-base Load and Multi-fuel-fired Combustion 

Turbines

Multiple commenters suggested that high efficiency simple 

cycle or fast-start NGCC technologies should be the BSER for 

non-base natural gas-fired load units. They explained that high 

efficiency simple cycle units and fast-start NGCC units are 
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actually more efficient when serving non-base load demand than 

NGCC units that are designed strictly for base load operation. 

Some commenters also suggested that we should subcategorize 

multi-fuel-fired combustion turbines, but did not provide any 

specific technologies that should be considered in the BSER 

analysis.

4. Identification of the BSER

After our evaluation of the comments and additional 

analysis, we identified the BSER for each subcategory of 

combustion turbine that we are finalizing: base load natural 

gas-fired units, non-base load natural gas-fired units, and 

multi-fuel-fired units. 

a. Base load natural gas-fired units

As described in the proposal, we evaluated CCS, NGCC, and 

high-efficiency simple cycle combustion turbines as the 

potential BSER for this subcategory. We selected NGCC as the 

BSER because it met all the BSER criteria. This section 

describes our response to issues raised by commenters and our 

rationale for maintaining that NGCC is the BSER for base load 

natural gas-fried combustion turbines.

(1) Partial CCS

Some commenters stated that CCS could be applied equally to 

both coal-fired and natural gas-fired EGUs. To support this 
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conclusion, the commenters pointed to a retired NGCC-with-CCS 

demonstration project, as well as a few overseas projects and 

projects in the early stages of development. While we have 

concluded that these commenters made strong arguments that the 

technical issues we raised at proposal could in many instances

be overcome, we have concluded that there is not sufficient 

information at this time for us to determine that CCS is 

adequately demonstrated for all base load natural-gas fired 

combustion turbines. 

While the commenters make a strong case that the existing 

and planned NGCC-with-CCS projects demonstrate the feasibility 

of CCS for NGCC units operating at steady state conditions, many 

NGCC units do not operate this way. For example, the Bellingham, 

MA and Sumitomo NGCC units cited by the commenters operated at 

steady load conditions with a limited number of starts and 

stops, similar to the operation of coal-fired boilers.565 In 

contrast, our base load natural gas-fired combustion turbine 

subcategory includes not only true base load units, but also 

some intermediate units that cycle more frequently, including 

 

565 As explained in Section V.J above, a new fossil fuel-fired 

steam generating EGU would, most likely, be built to serve base 

load power demand exclusively and would not be expected to 

routinely start up, shut down, or ramp its capacity factor in 

order to follow load demand. Thus, planned start-up and shutdown 

events would only be expected to occur a few times during the 

course of a 12-operating-month compliance period.
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fast-start NGCC units that sell more than 50 percent of their 

potential output to the grid. Fast-start NGCC units are designed 

to be able to start and stop multiple times in a single day and 

can ramp to full load in less than an hour. In contrast, coalfired EGUs take multiple hours to start and ramp relatively 

slowly. These differences are important because we are not aware 

of any pilot-scale CCS projects that have demonstrated how fast 

and frequent starts, stops, and cycling will impact the 

efficiency and reliability of CCS. Furthermore, for those 

periods in which a NGCC unit is operating infrequently, the CCS 

system might not have sufficient time to start up. During these 

periods, no CO2 control would occur. Thus, if the NGCC unit is 

intended to operate for relatively short intervals for at least 

a portion of the year, the owner or operator could have to 

oversize the CCS to increase control during periods of steadystate operation to make up for those periods when no control is 

achieved by the CCS, leading to increased costs and energy 

penalties. While we are optimistic that these hurdles are 

surmountable, it is simply premature at this point to make a 

finding that CCS is technically feasible for the universe of 

combustion turbines that are covered by this rule. 

Notably, the Department of Energy has not yet funded a CCS 

demonstration project for a NGCC unit, and no NGCC-with-CCS 

demonstration projects are currently operational or being 
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constructed in the U.S. In contrast, multiple CCS demonstration

projects for coal-fired units are in various stages of 

development throughout the U.S., and a full-capture system is in 

operation at the Boundary Dam facility in Canada. See Sections 

V.E and D above.

One commenter suggested that not having CCS as the BSER for 

combustion turbines would ultimately halt the development of CCS

in the U.S. We disagree. A number of coal-fired power plants are 

currently being built with CSS, while some existing plants are 

considering CCS retrofits. Moreover, the NSPS sets the minimum 

level of control for new sources. We expect that state air 

agencies and other air permitting authorities will evaluate CCS 

when permitting new NGCC power plants, taking into consideration

case-specific parameters, like operating characteristics, to 

determine whether CCS could be BACT or LAER in specific 

instances. While the NGCC-with-CCS units that currently are in 

the planning stages do not provide us with enough assurance to 

determine that CCS is adequately demonstrated for combustion 

turbines, it is our expectation that these units and others to 

come will provide additional information for both permitting 

reviews and the next NSPS review in eight years.

(2) NGCC turbines

Regarding the advanced NGCC technologies advocated by 

several commenters, the EPA has concluded that the term 
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“advanced” simply refers to incremental improvements to 

traditional NGCC designs, not a new and unique technology. These 

incremental improvements include higher firing temperatures in 

the turbine engine, increasing the number of steam pressures,

and adding a reheat cycle to the steam cycle. The emission rates 

achieved by these so-called “advanced” technologies were 

included within the data set of newer NGCC designs that we used 

to establish the final emission standards. In addition, our

review of the operating data for NGCC power blocks installed 

since 2000 indicates that a unit’s mode of operation in response 

to system demand (e.g., capacity factor) affects efficiencies 

achieved to the extent that we cannot evaluate the impact of 

particular subcomponents used within the power block. As a 

result, a conventional NGCC power block located in a region of 

the country where system demand requires the power block to run 

continuously at a steady high load can achieve higher 

efficiencies than an “advanced” NGCC power block located in a 

region where system demand requires the power block to cycle on 

and off to match system demand. For this reason, our data set 

included a large population of technologies and load conditions 

to ensure that new NGCC power blocks can achieve the final

emission standards in all regions of the country. 

As we explained in the proposal, NGCC technology meets all 

of the BSER criteria. For base load functions, NGCC units are 
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technically feasible, cost-effective (indeed, less expensive 

than simple cycle combustion turbines), and have no adverse 

energy or environmental impacts. Moreover, NGCC units reduce 

emissions because they have a lower CO2 emission rate than simple 

cycle units. Finally, selecting NGCC as the BSER will promote 

the development of new technology, such as the incremental 

improvements advocated by the commenters, which will further 

reduce emissions in the future.

Some commenters suggested that the costs and efficiency 

impacts of startup and shutdown events are higher for NGCC units

than for simple cycle units. Consequently, we refined the LCOE 

costing approach used at proposal by adding these additional

costs and efficiency impacts to our cost comparison. Even 

accounting for these new costs and impacts, we found that NGCC

technology results in a lower cost of electricity than simple 

cycle technology when a unit’s electric sales exceed 

approximately one-third of its potential electric output. The 

final percentage electric sales criterion for the base load 

natural gas-fired combustion turbine subcategory is based on the 

sliding scale. This means that the dividing line between the 

base load subcategory and the non-base load subcategory will 

change depending on a unit’s nameplate design efficiency. For a 

conventional simple cycle turbine, the base load subcategory 

will begin at around 33 percent electric sales, while for a 
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newer fast-start NGCC turbine, the base load subcategory will 

begin at approximately 50 percent electric sales. Anywhere 

within this range, our cost calculations have shown that NGCC

technology is more cost-effective than simple cycle technology.

Therefore, we are finalizing our determination that modern, 

efficient NGCC technology is the BSER for base load natural-gas 

fired combustion turbines.

(3) Simple cycle turbines

Many commenters mistakenly thought that the EPA proposed to 

require some simple cycle combustion turbines to meet an 

emission standard of 1,000 lb CO2/MWh-g, a level that they assert 

is unachievable. On the contrary, the EPA is not finding that 

NGCC technology and a corresponding emission standard of 1,000 

lb CO2/MWh-g is the BSER for simple cycle turbines. Instead, the 

EPA is finding that NGCC technology is the BSER for base load 

turbine applications. This means that if an owner or operator 

wants to sell more electricity to the grid than the amount 

derived from a unit’s nameplate design efficiency calculated as 

a percentage of potential electric output, then the owner or 

operator should install a NGCC unit. If the owner or operator 

elects to install a simple cycle turbine instead, then the 

practical effect of our final standards will be to limit the 

electric sales of that unit so that it serves primarily peak 

demand, not to subject it to an unachievable emission standard.
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b. Non-base load natural gas-fired load units

To identify the BSER for non-base load natural gas-fired 

units, we evaluated a range of technologies, including partial 

CCS, high-efficiency NGCC technology designed for base load 

applications, fast-start NGCC, high-efficiency simple cycle 

units (i.e., aeroderivative turbines), and clean fuels. For each 

of these technologies, we considered technical feasibility, 

costs, energy and non-air quality impacts, potential for

emission reductions, and ability to promote technology.

While CCS would result in emission reductions and promote

the development of new technology, we concluded that CCS does 

not meet the BSER criteria because the low capacity factors and 

irregular operating patterns (e.g., frequent starting and 

stopping and operating at part load) of non-base load units make

the technical challenges associated with CCS even greater than 

those associated with base load units. In addition, because the 

CCS system would remain idle for much of the time while these 

units are not running, the cost-effectiveness of CCS for these 

units would be much higher than for base load units.

We have also concluded that the high-efficiency NGCC units

designed for base load applications do not meet any of the BSER 

criteria for non-base load units. First, non-base load units 

need to be able to start and stop quickly, and NGCC units 

designed for base load applications require relatively long 
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startup and shutdown periods. Therefore, conventional NGCC 

designs are not technically feasible for the non-base load 

subcategory. Also, non-base load units operate less than 10 

percent of the time on average. As a result, conventional NGCC 

units designed for base load applications, which have relatively 

high capital costs, will not be cost-effective if operated as 

non-base load units. In addition, it is not clear that a 

conventional NGCC unit will lead to emission reductions if use 

for non-base load applications. As some commenters noted, 

conventional NGCC units have relatively high startup and 

shutdown emissions and poor part-load efficiency, so emissions 

may actually be higher compared with simple cycle technologies 

that have lower overall design efficiencies but better cycling 

efficiencies. Finally, requiring conventional NGCC units as the 

BSER for non-base load combustion turbines would not promote 

technology because these units would not be fulfilling their

intended role. In fact, it could hamper the development of 

technologies with lower design efficiencies that are 

specifically designed to operate efficiently as non-base load 

units (i.e., high-efficiency simple cycle and fast-start NGCC 

units). For all these reasons, we have concluded that 

conventional NGCC units designed for base load applications are

not the BSER for non-base load natural gas-fired units.
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Compared to conventional NGCC technology, fast-start NGCC 

units have lower design efficiencies, but are able to start and 

ramp to full load more quickly. Therefore, it is possible that 

requiring fast-start NGCC as the BSER for non-base load units 

would result in emission reductions and further promote the 

development of fast-start NGCC technology, which is relatively 

new and advanced. However, because the majority of non-base load 

combustion turbines operate less than 10 percent of the time, it 

would be cost-prohibitive to require fast-start NGCC, which have 

relatively high capital costs compared to simple cycle turbines,

as the BSER for all non-base load applications. Also, as we 

explained above in Section IX.B.2, we do not have sufficient 

emissions data for fast-start NGCC units operating over the full 

range of non-base load conditions (e.g., peaking, cycling, 

etc.), so we would not be able to establish a reasonable 

emission standard.

High-efficiency simple cycle turbines are primarily used 

for peaking applications. High-efficiency simple cycle turbines 

often employ aeroderivative designs because they are more 

efficient at a given size and are able to startup and ramp to 

full load more quickly than industrial frame designs. Requiring 

high-efficiency simple cycle turbines as the BSER could result 

in some emission reductions compared with conventional simple 

cycle turbines. It would also promote technology development by 
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incentivizing manufacturers to increase the efficiency of their 

simple cycle turbine models. However, aeroderivative designs

have higher initial costs that must be weighed against the 

specific peak-load profiles anticipated for a particular new 

non-base load unit. Many utility companies have elected to 

install the heavier industrial frame turbines because the 

ramping capabilities of aeroderivative turbines are not required 

for their system demand profiles (i.e., the speed and durations 

of daily changes in electricity demand), and the fuel savings do 

not justify the higher initial costs. We currently do not have 

precise enough costing information to compare the costeffectiveness of aeroderivative turbines and industrial frame 

turbines for all non-base load applications. Determining costeffectiveness is further complicated because the efficiencies of 

the available aeroderivative and industrial frame technologies 

significantly overlap. For example, the efficiencies of 

aeroderivative turbines range from 32 to 39 percent, while the 

efficiencies of industrial frame turbines range from 30 to 36 

percent. Based on these cost uncertainties, we cannot conclude 

that high-efficiency simple cycle turbines are the BSER for 

natural gas-fired non-base load applications at this time. 

The final option that we considered for the BSER was clean 

fuels, specifically natural gas with a small allowance for 

distillate oil. The use of clean fuels is technically feasible 
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for non-base load units. Based on available EIA data,

566 natural 

gas comprises more than 96 percent of total heat input for 

simple cycle combustion turbines. In addition, natural gas is 

frequently the lowest cost fossil fuel used in combustion 

turbines, so it is cost-effective. Clean fuels will also result 

in some emission reductions by limiting the use of fuels with 

higher carbon content, such as residual oil. Finally, the use of 

clean fuels will not have any significant energy or non-air 

impacts. Based on these factors, the EPA has determined that the 

BSER for non-base load natural gas-fired units is the use of

clean fuels, specifically natural gas with a small allowance for 

distillate oil. Natural gas has approximately thirty percent 

lower CO2 emissions per million Btu than other fossil fuels 

commonly used by utility sector non-base load units.

c. Multi-fuel-fired units

To identify the BSER for multi-fuel-fired units, we again 

evaluated CCS, NGCC technology, high-efficiency simple cycle 

units (i.e., aeroderivative turbines), and clean fuels. For each 

of these technologies we considered technical feasibility, 

costs, energy and non-air quality impacts, emission reductions, 

and technology promotion. For many of the same reasons we 

provided above in our discussion of the BSER for non-base load 

 

566 http://www.eia.gov/electricity/data/eia923/.
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natural gas-fired combustion turbines, only clean fuels meets 

the BSER criteria for multi-fuel-fired units.

While CCS would result in emission reductions and the 

promotion of technology, we concluded that CCS does not meet the 

BSER criteria because multi-fuel-fired units tend to start, 

stop, and operate at part load frequently. Also, there are 

impurities and contaminants in some alternate fuels which make

the technical challenges of applying CCS to multi-fuel-fired 

units greater than for natural gas-fired units. 

In regards to NGCC technology, we have concluded that it is 

technically feasible, would result in emission reductions, is 

cost-effective, and would promote the development of technology. 

However, a BSER determination based on the use of NGCC 

technology could pose challenges for facilities operating in 

remote locations and certain industrial facilities. In remote 

locations, the construction of a NGCC facility is often not 

practical because it requires larger capital investments and 

significant staffing for construction and operation. In 

contrast, simple cycle turbines are cheaper and can be operated 

with minimal staffing. Also, many industrial facilities do not 

have the space available to build a HRSG and the associated 

cooling tower. Therefore, requiring NGCC as the BSER could have 

unforeseen energy impacts at these types of facilities. 

Moreover, these same kinds of facilities also burn by-product 
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fuels. Faced with a decision to install an NGCC unit, these 

facilities might seek alternative energy options, which could 

lead to increased flaring or venting of by-product fuels because 

they are no longer being burned onsite for energy recovery. 

Therefore, in light of these potential energy and non-air 

quality impacts, we have concluded that NGCC technology is not 

the BSER for multi-fuel-fired combustion turbines.

Similarly, while high-efficiency simply cycle turbines

would result in emission reductions and promote the advancement 

of this technology, we are not confident that high-efficiency 

simple cycle units are technically feasible or cost-effective 

for this subcategory. Aeroderivative turbines are not as

flexible with regards to what fuels that can be burned. Because

by-product fuels vary in composition, it is not clear that all 

by-products fuels could be burned in a high-efficiency simple 

cycle turbine. In addition, even if a by-product fuel could be 

burned in an aeroderivative turbine, we do not have information 

on the potential for increased maintenance costs, we so cannot 

determine whether using high-efficiency simple cycle turbines 

would be cost-effective.

The final option that we considered for the BSER was clean 

fuels. The use of clean fuels is technically feasible and costeffective. The use of clean fuels also provides an

environmentally beneficial alternative to the flaring or venting
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of by-product fuels and limits the use of dirtier fuels with 

higher CO2 emission rates, such as residual oils. Clean fuels

also promote technology development by allowing manufacturers to 

develop new combustion turbine designs that are capable of 

burning by-product fuels that currently cannot be burned in 

combustion turbines. Finally, the use of clean fuels does not 

have any significant energy or non-air quality impacts. Based on 

these factors, the EPA has determined that the BSER for multifuel-fired combustion turbines is the use of clean fuels. 

D. Achievability of the Final Standards

We are finalizing emission standards for three

subcategories of combustion turbines. Specifically, units that 

sell electricity in excess of a threshold based on their design 

efficiency and that burn more than 90 percent natural gas (i.e., 

base load natural gas-fired units) will be subject to an outputbased standard. The output-based standard is based on the

performance of existing NGCC units and takes into account a 

range of operating conditions, future degradation, etc. Units 

not meeting either the percentage electric sales or natural gasuse criteria (i.e., non-base load natural gas-fired and multifuel units, respectively) will be subject to an input-based

standard based on the use of clean fuels. This section 

summarizes what emission standards we proposed and related 

issues we solicited comment on, describes the comments we 
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received regarding the proposed emission standards and our

responses to those comments, and our rationale for the final 

emission standards.

1. Proposed Standards

For large newly constructed, modified, and reconstructed 

stationary combustion turbines (base load rating greater than 

850 MMBtu/h), we proposed an emission standard of 1,000 lb 

CO2/MWh-g. For small stationary combustion turbines (base load 

rating of 850 MMBtu/h or less), we proposed an emission standard 

of 1,100 lb CO2/MWh-g. We also solicited comment on a range of 

950 – 1,100 lb CO2/MWh-g for large stationary combustion turbines 

and a range of 1,000 – 1,200 lb CO2/MWh-g for small stationary 

combustion turbines. 

In addition, we solicited comment on increasing the size 

distinction between large and small stationary combustion 

turbines to 900 MMBtu/h to account for larger aeroderivative 

designs; increasing the size distinction to 1,000 MMBtu/h to 

account for future incremental increases in base load ratings;

increasing the size distinction to between 1,300 to 1,800 

MMBtu/h; and eliminating the size subcategories altogether. To 

account for potential reduced efficiencies when units are not 

operating at base load, we also solicited comment on whether a 

separate, less stringent standard should be established for nonbase load combustion turbines.
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2. Comments

As described previously, we are not finalizing the sizebased subcategories that we proposed and instead are finalizing 

emission standards for sales- and fuel-based subcategories. 

Specifically, we are finalizing emission standards for three 

subcategories of stationary combustion turbines: base load 

natural-gas fired units, non-base load natural gas-fired units 

and multi-fuel-fired units. The relevant comments concerning the 

emission standards for the first two subcategories are discussed 

below. Any comments we received supporting tiered emission 

standards are included in the discussion of non-base load 

natural gas-fired units. We did not receive comments on an 

appropriate emission standard for multi-fuel-fired units.

a. Emission standards for base load natural gas-fired units

Many commenters stated that the proposed emission standards 

did not properly take into account the losses in efficiency that 

occur due to long-term degradation over multiple decades,

operation at non-base load conditions (load cycling, frequent 

startups and shutdowns, and part-load operations), site-specific 

factors such as ambient conditions and cooling technology, and 

secondary fuel use (e.g., distillate oil). These commenters 

stated that the EPA should conduct a more comprehensive analysis 

that addresses worst-case conditions for each of these factors.

They also stated that all of the units included in the analysis 
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supporting the proposal were relatively new and therefore have 

experienced limited degradation. The commenters stated that,

while some degradation in efficiency can be recovered during 

periodic maintenance outages, it is not always possible or 

feasible to repair a degraded component immediately because 

repairs often involve extended outages that must be scheduled 

well in advance. They stated that a new unit that initially 

could meet the standard at base load conditions can experience 

increasing heat rates with age even when adhering to the 

manufacturer's recommended maintenance program.

Some commenters stated that the proposed standards were 

derived by looking at emissions data from years with 

historically low natural gas prices. They surmised that the NGCC 

units were taking advantage of these prices by running at 

historically high capacity factors and concluded that the 

efficiencies and CO2 emission rates underlying the proposed 

standards were not representative of periods with higher natural 

gas prices. Other commenters said that many NGCC units are 

increasingly required to cycle and operate at lower capacities 

(compared to the proposal's baseline) to accommodate hourly 

variations in intermittent renewable generation. They 

anticipated that this type of generation will increase, 

requiring NGCC units to start, stop, and operate at part load 

more frequently than in the past, increasing CO2 emissions. 
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Some commenters indicated that, during startup, combustion 

turbines must be operated at low load for extended periods to 

gradually warm up the HRSG to minimize thermal stresses on 

pressure vessels and boiler tubes. During these startup periods, 

significant CO2 emissions occur, but steam production is not 

sufficient for the steam turbine generator to produce 

electricity. They also stated that a similar situation occurs 

during shutdown when the steam cycle does not generate 

electricity, but the combustion turbine is still combusting fuel 

as it proceeds through the shutdown process. These commenters 

recommended that the EPA could address these issues by creating 

a subcategory for NGCC units that cycle and operate at 

intermediate load.

Many commenters said that site-specific factors can often 

preclude operators from achieving design efficiencies based on 

ISO conditions. These factors include high elevations, high 

ambient temperatures, and cooling system constraints. They

stated that local water temperatures can impact condenser 

operating pressure and heat rates. They also said that areas 

with limited water resources could require systems that rely on 

air-cooled condensers, which cannot achieve thermal efficiencies 

comparable to water-cooled plants. These commenters stated that 

the final rule should include provisions for addressing sitespecific constraints that preclude individual affected EGUs from 
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achieving the emissions rates achieved on average by other 

sources.

Some commenters stated that the proposed standards for 

modified and reconstructed combustion turbines would foreclose 

future opportunities for operators to undertake projects to 

restore the performance of both degraded units subject to the 

NSPS and existing, pre-NSPS units. They said that it is not 

possible to bring older combustion turbines (built prior to the 

year 2000) up to the efficiency levels of modern units because 

many newer technological options that deploy higher temperatures 

are not available for pre-2000 combustion turbines. 

Commenters from the power sector generally supported 

increasing the standards to 1,100 lb CO2/MWh-g and 1,200 lb 

CO2/MWh-g for the newly constructed large and small turbines, 

respectively. They also advocated finalizing standards for 

modified and reconstructed standards that are 10 percent higher 

than the final standards for new sources because combustion 

turbines constructed prior to 2000 were not included in the 

EPA's analysis.

Conversely, some commenters stated that the proposed 

standards for combustion turbines do not reflect the emission 

rates that are achievable by modern, efficient NGCC power 

blocks. These commenters stated that the appropriate standard, 

consistent with Congressional objectives under CAA section 111, 
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should be 800 lb CO2/MWh-g based on the performance of the lowest 

emitters in the CAMD database. Some commenters stated that a 

standard of 850 lb CO2/MWh-g reflects BSER for high-capacity 

factor units because half of the NGCC units in the CAMD database 

are achieving this level of emissions. One commenter from the 

power sector who operates NGCC power plants stated that the 

final standard for new large combustion turbines should be 925 

lb CO2/MWh-g. Another also commenter supported an emission 

standard of 925 lb CO2/MWh-g, which is consistent with recent 

BACT determinations in the state of New York. Several other 

commenters stated that a reasonable standard for new large 

combustion turbines should be 950 lb CO2/MWh-g and that the final 

standard for new small combustion turbines should be 1,000 lb

CO2/MWh-g. Numerous commenters stated that the final standards

for new sources should not exceed 1,000 lb CO2/MWh-g for either 

large or small combustion turbines. Other commenters stated 

that, because the standards were developed based on emission 

rates that are being achieved by the majority of existing units, 

the final standards should be the same for new, modified, and 

reconstructed units. 

b. Emission standards for non-base load natural gas-fired units

and multi-fuel-fired units

Many commenters stated that the EPA cannot finalize “no 

emission standard” for non-base load units, which the EPA 
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solicited comment on in the broad applicability approach. They 

argued that this approach was not consistent with the definition 

of “standard of performance” in CAA section 111(a)(1), which 

requires there to be an “emission limitation” that reflects a 

“system of emission reduction.” Some commenters recommended that 

non-base load units should be subject to work practice 

standards, such as operating safely with good air pollution 

control practices, including CO2 monitoring and reporting 

requirements. Other commenters pointed to recent PSD permits 

that include tiered emission limits for the different roles 

served by combustion turbines. They cited BACT limits from 1,328 

to 1,450 lb CO2/MWh-g for peaking units. One commenter supported 

tiered limits consistent with recent BACT determinations in the 

state of New York, which include limits for simple cycle 

combustion turbines of 1,450 lb CO2/MWh-g. An air quality 

regulator from a state with rapidly increasing renewable 

generation supported a limit of 825 lb CO2/MWh-g for all base 

load NGCC units; 1,000 lb CO2/MWh-g for large intermediate load 

NGCC units; 1,100 lb CO2/MWh-g for small intermediately load NGCC 

units. This commenter also recommended that the EPA set a 

numerical limit specifically for peaking units after the 

completion of a peaking unit-specific BSER analysis. Several 

commenters supported tiered standards based on capacity factor. 

They proposed 825 lb CO2/MWh-g for base load units (those 
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operating over 4,000 hours annually), 875 lb CO2/MWh-g for 

intermediate and load-following units (those operating between 

1,200 and 4,000 hours annually), and 1,100 lb CO2/MWh-g for 

peaking units (those operating less than 1,200 hours per year).

3. Final Standards

a. Newly constructed base load natural gas-fired units

In evaluating the achievability of the base load natural 

gas-fired emission standard, we focused on three types of data. 

Specifically, we looked at existing NGCC emission rates, recent 

PSD permit limits for CO2 emissions, and NGCC design efficiency 

data and specifications. Based on this analysis, we have 

concluded that an emission rate of 1,000 lb CO2/MWh-g is 

appropriate for all base load natural gas-fired combustion 

turbines, regardless of size.

Since the standards were proposed, the EPA has expanded the 

NGCC emission rate analysis that supported the proposed emission 

standards to include emissions information for NGCC units that 

commenced operation in 2011, 2012, and 2013, and updated the 

emissions data to include emissions through 2014. In our 

analysis, we evaluated 346 NGCC units with online dates ranging 

from 2000 to 2013. The analysis included emissions data from 

2007 to 2014 as submitted to the EPA’s CAMD. The average maximum 

12-operating-month CO2 emission rate for all NGCC units was 897 
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lb CO2/MWh-g, with individual unit maximums ranging from 751 to 

1,334 lb CO2/MWh-g.

Consistent with our proposed size-based subcategories, we 

also reviewed the emissions data for small and large NGCC units

separately. For small units, we evaluated emissions data from 17 

NGCC units with heat input ratings of 850 MMBtu/h or less. These 

units had an average maximum 12-operating-month CO2 emission rate 

of 953 lb/MWh-g. Individual unit maximum emission rates ranged 

from 898 to 1,175 lb CO2/MWh-g. Two of the units had a maximum 

emissions rate equal to or greater than 1,000 lb CO2/MWh-g.

568

However, one of the units with a maximum emission rate above

1,000 lb CO2/MWh was only selling approximately 20 percent of its 

potential electric output (significantly below the designspecific percentage electric sales threshold) when the emission 

rate occurred. If this unit were a new unit, the applicable 

emission standard would be the heat input-based clean fuels 

standard, and the unit would not be out of compliance.

Therefore, 16 of the 17 existing small NGCC units have 

demonstrated that an emission rate of 1,000 lb CO2/MWh-g is 

achievable. In addition, the six newest units, which commenced 

construction between 2007 and 2012, all have maximum 12-

 

568 For emission standards of 1,000 lb CO2/MWh-g and above, the 

emission standard uses three significant figures. See Section 

X.D.
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operating-month emission rates of less than 950 lb CO2/MWh-g. 

While these units might not be old enough to have experienced 

degredation, their maximum emission rates demonstrate that the

final standard of 1,000 lb CO2/MWh-g includes a significant

compliance margin for any future degredation.

For large units, the average maximum 12-operating-month 

emission rate was 895 lb CO2/MWh-g, with individual unit maximum 

emission rates ranging from 751 to 1,334 lb CO2/MWh-g. Twentythree of the 328 large NGCC units had maximum 12-operating-month 

emission rates greater than 1,000 lb CO2/MWh. While we do not 

have precise design efficiency information for each of these 

units, and thus cannot calculate the precise percentage electric 

sales threshold to which each unit would be subject, it appears 

that all of the emission rates in excess of 1,000 lb CO2/MWh-g 

occurred during periods when electric sales were low and would 

be below the threshold. Thus, if these units were new units, 

they would only have to comply with the heat input-based clean 

fuels standard. Therefore, essentially all existing NGCC units 

would have been in compliance with the final emission standard.

We note also that there are 51 new NGCC units that have started 

operation since 2010, and the average maximum 12-operating-month 

emission rate for these units is 833 lb CO2/MWh-g. Therefore, the 

final emission standard includes a very significant compliance 
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margin to account for any potential future degredation of large 

units. 

To evaluate degredation further, the EPA reviewed the 

emission rate information for the 55 oldest NGCC units in our 

data set (i.e., units that came online in 2000 and 2001). 

According to the commenters, we should expect to see degredation 

when reviewing the annual emissions data for these turbines 

because they are 14 to 15 years old. However, we did not see any 

sign of degredation. The CO2 rates for these turbines have little 

standard deviation between 2007 and 2014. In addition, there 

were many instances where the CO2 emission rate of a unit

actually decreased with age. This indicates that the efficiency 

of the unit is increasing, possibly as a result of good 

operating and maintenance procedures or upgrades to equipment 

that improved efficiency beyond the original design. Based on 

these findings, we have concluded that our analysis adequately 

accounts for potential degredation.

We also evaluated the impact of elevation, ambient 

temperature, cooling type, and operating conditions (startups, 

shutdowns, and average run time per start) because commenters 

indicated that these could affect a unit's ability to achieve 

the standard. We saw little correlation between elevation or 

ambient temperature and emission rate. In addition, any 

correlation was relatively small and would have an insignificant 
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impact on the ability of a unit to achieve the final standard. 

We identified 32 large NGCC units with dry cooling towers. The 

average maximum 12-operating-month emission rate for this group 

of units was 875 lb CO2/MWh. This rate was actually lower than 

the average rate for the large NGCC group as a whole. Based on 

these findings, we have concluded that the final emission 

standard will not limit the use of dry cooling technologies. 

Finally, the EPA evaluated the impact of run time per start, 

average duty cycle, and number of starts on emission rates.

While these factors do influence emission rates, the non-base 

load natural gas-fired subcategory inherently addresses 

efficiency issues related to operating conditions.

In addition to evaluating existing NGCC emissions data, the 

EPA reviewed the CO2 emission limits included in PSD 

preconstruction permits issued since January 1, 2011. We 

evaluated all permit limits over an annual period. In total, we 

identified 31 major source PSD permits with 39 discrete limits 

on CO2 emissions. Eight of the limits were expressed in terms of 

lb/h or tons per year, so we did not include them in the 

analysis. In addition, one CHP unit that generates electricity 

and supplies steam to a chemical plant was in the data set. This 

facility had a permit limit of 1,362 lb CO2/MWh based only on 

gross electrical output and does not account for useful thermal 

output. Therefore, we did not include it in the analysis either. 
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Finally, we excluded two permits that did not clearly specify if 

the output-based standard was on a gross or net basis. 

The remaining 28 permit limits were expressed in lb CO2/MWh 

or a heat rate basis that could be converted to lb CO2/MWh. Eight 

permit limits were based on net output, ranging from 774-936 lb 

CO2/MWh-n. The lowest emission limit was for a hybrid power plant 

with a solar component that could contribute up to 50 MW. Twenty 

permit limits were based on gross output, ranging from 833-1,100 

lb CO2/MWh-g. Of these 28 permit limits, the only limit in excess 

of our final emission standard of 1,000 lb CO2/MWh-g is for a 

relatively small NGCC unit (base load rating of 366 MMBtu/h)

that commenced construction prior to the proposal and thus will 

not be subject to the requirements of this final rule.

Each of the permit limits discussed above that is 1,000 lb

CO2/MWh or less includes all periods of operation, including 

startup, shutdown and malfunction events. In addition, each 

permit limit was set after backup and additional fuel use were

taken into consideration. While some permits restrict fuel use 

to only natural gas, others allow limited usage (duration and 

type) of backup and other fuels. For example, the Pioneer Valley 

Energy Center has unrestricted use of natural gas, but can burn

ultra-low sulfur diesel (ULSD) for up to 1,440 hours per 12-

month period. This permit requires the unit to comply with a

limit of 895 lb CO2/MWh-n even when burning up to 16 percent 
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distillate oil. Each permit limit takes into account the mode of 

operation for the combustion turbine. For example, the permit 

for the Lower Colorado River Authority's Ferguson plant 

evaluated emission limits for the plant at 50, 75, and 100 

percent gross load. The emission limit of 918 lb CO2/MWh-n

accounts for the unit’s expected operation at 50 percent gross 

load. For NGCC units with duct burners on their HRSGs, the 

permit limits account for the hours of operation with duct 

burners firing. Finally, most of these permits include 

compliance margins to account for efficiency losses due to 

degradation and other factors (e.g., actual operating 

parameters, site-specific design considerations, and the use of 

backup fuel). In total, these compliance margins result in a 10 

to 13 percent increase in the permitted CO2 emission limits, yet 

all of the limits except one were still below 1,000 lb CO2/MWh-g. 

Finally, we also reviewed NGCC design efficiency data and 

specifications submitted to Gas Turbine World. Specifically, we 

review the reported efficiency data for 88 different 60 Hz NGCC

units manufactured by Alstom, GE Energy Aeroderivative and Heavy 

Duty, Mitsubishi Heavy Industries, Pratt & Whitney, Rolls-Royce, 

and Siemens Energy. The designs ranged in model year from 1977 

to 2011, capacities ranged from 31 to 1,026 MW, and base load 

ratings ranged from 236 to 3,551 MMBtu/h. The average reported 

design emission rate for these units was 834 lb CO2/MWh-n and 
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ranged from 725 to 941 lb CO2/MWh-n. Therefore, our optional 

standard of 1,030 lb CO2/MWh-n would allow for an average 

compliance margin of 24 percent, with a range from 10 to 42 

percent, over the design rate. Ninety-five percent of designs 

would have a compliance margin of 13 percent or more, the top 

end of the range of compliance margins determined to be 

appropriate in the PSD permits we reviewed. 

Because some commenters were concerned that smaller NGCC 

units will not be able to achieve the emission standard, we 

specifically considered the design rates for smaller units. For 

the 52 small units (base load rating of 850 MMBtu/h or less), 

the average design emission rate was 865 lb CO2/MWh and ranged 

from 796 to 941 lb CO2/MWh-n. Therefore, our optional standard of

1,030 lb CO2/MWh-n would allow for an average compliance margin 

averaged 19 percent, with a range of 10 to 29 percent, over the 

design rate. Ninety-five percent of small NGCC designs would 

have a compliance margin of 13 percent or more. 

We further refined our analysis by only considering the 

most efficient design for a given combustion turbine engine. For 

example, GE Energy Aeroderivative offers four design options for 

its LM2500 model-type, all with a rating of approximately 45 MW. 

The design emission rates for these various options range from 

827 to 914 lb CO2/MWh-n. When only the most efficient models for 

a particular combustion turbine engine design are considered, 
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all NGCC models have over a 13 percent compliance margin. In 

other words, developers of new base load natural gas-fired 

combustion turbines concerned about the achievability of the 

final standard have multiple more efficient options offered by 

the same manufacturer. Therefore, we have concluded that the 

final emission standard allows sufficient flexibility for end 

users to select an NGCC design appropriate for their specific 

requirements. 

After considering these three sources of information -

actual NGCC emission rate data, PSD permit limits for NGCC 

facilities, and NGCC design information – we have concluded that 

a standard of 1,000 lb CO2/MWh is both achievable and appropriate 

for newly constructed base load natural gas-fired combustion 

turbines. While we anticipate that the large majority of new 

NGCC units will operate well below this emission rate, this 

standard provides flexibility for developers to take into 

account site-specific conditions (e.g., ambient conditions and 

cooling system), operating characteristics (e.g., part-load 

operation and frequent starting and stopping), and reduced 

efficiency due to degredation. The standard also accommodates 

the full size range of turbines.

We also expect multiple technology developments to further

increase the performance of new base load natural gas-fired 

stationary combustion turbines. Vendors continue to improve the 
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single cycle efficiency of combustion turbines. The use of more 

efficient combustion turbine engines improves the overall 

efficiency of NGCC facilities. In addition, existing smaller 

NGCC facilities were likely designed using single or dual 

pressure HRSGs without a reheat cycle. New designs can

incorporate three pressure steam generators with a reheat cycle 

to improve the overall efficiency of the NGCC facility. Finally, 

additional technologies to reduce emission rates for new 

combustion turbines include CHP and integrated non-emitting 

technologies. For example, an NGCC unit that is designed as a 

CHP unit where ten percent of the overall output is useful 

thermal output would have an emission rate approximately five 

percent less than an electric only NGCC. In sum, we believe that 

our final emission standards of 1,000 lb CO2/MWh-g and 1,030 lb 

CO2/MW-n are not only readily achievable, but likely 

conservative.

b. Reconstructed base load natural gas-fired units

We disagree with commenters that stated that reconstructed 

combustion turbines will not be able to achieve the proposed 

emission standards. For the reasons listed below, we have 

concluded that an existing base load natural-gas fired unit that 

reconstructs can achieve an emission rate of 1,000 lb CO2/MWh-g, 

regardless of its size.
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Highly efficient NGCC units include (1) an efficient 

combustion turbine engine, (2) an efficient steam cycle, and (3) 

a combustion turbine exhaust system that is “matched” to the 

steam cycle for maximum efficiency. In order for an existing 

NGCC unit to trigger the reconstruction provisions, the unit 

would have to essentially be entirely rebuilt. This would 

involve extensive upgrades to both the combustion turbine engine 

and the HRSG. Therefore, a reconstructed NGCC unit will be able 

to maximize the efficiency of the turbine engine and the steam 

cycle and match the two for maximum efficiency. 

According to comments submitted in response to the proposal 

for existing sources under CAA section 111(d), there are various 

options available to improve the efficiency of existing 

combustion turbines. One combustion turbine manufacturer 

provided comments describing specific technology upgrades for

the compressor, combustor, and gas turbine components. This 

manufacturer stated that operators of existing turbines can 

replace older internal components along the gas path with stateof-the-art components that have higher aerodynamic efficiencies 

and improved seal designs. These gas-path enhancements enable 

existing sources to both improve the efficiency of the turbine 

engine and improve the systems used for cooling the metal parts 

along the hot-gas path to allow existing systems to achieve 

higher operating temperatures. In total, the manufacturer stated 
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that utilities deploying these gas-path improvements on 

reconstructed industrial frame combustion turbines with nominal 

output ratings of 170 to 180 MW can increase their output by 10 

MW while reducing CO2 emissions by more than 2.6 percent compared 

to baseline. In addition to gas-path and software improvements, 

the manufacturer stated that the newest low-NOX combustor designs 

can be retrofitted on modified and reconstructed turbines to 

achieve lower NOX emissions, which improves turndown (i.e., to 

enable stable operations at lower loads compared to the lowest 

stable load achievable at baseline conditions) and efficiencies 

across all load conditions. The manufacturer indicated that 

operators of existing combustion turbines deploying both stateof-the-art gas-path and software upgrades and combustor upgrades 

can increase output on frame-style turbines with nominal output 

ratings of 170 to 180 MW by 14 MW, while reducing CO2 emissions 

by 2.8 percent. In addition to the preceding upgrades, the 

manufacturer stated that existing combustion turbines can 

achieve the largest efficiency improvements by upgrading 

existing compressors with more advanced compressor technologies, 

potentially improving the combustion turbine's efficiency by an 

additional 3.8 percent. Thus, the total potential CO2 emissions 

reductions for just the combustion turbine portion of a combined 

cycle unit is 6.6 percent.
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In addition to upgrades to the combustion turbine engine, 

an operator reconstructing a NGCC unit will have the opportunity 

to improve the efficiency of the HRSG and steam cycle. For

example, a steam turbine manufacturer identified three retrofit 

technologies available for reducing the CO2 emissions rate of 

existing steam turbines by 1.5 to 3 percent: (1) steam-path 

upgrades can minimize aerodynamic and steam leakage losses; (2) 

replacement of the existing high pressure turbine stages with 

state-of-the-art stages capable of extracting more energy from 

the same steam supply; and (3) replacement of low-pressure 

turbine stages with larger diameter components that extract 

additional energy and that reduce velocities, wear, and 

corrosion.

In addition, an operator reconstructing a NGCC unit could 

upgrade the entire steam cycle. For example, combined cycle 

units originally constructed with only a single pressure level 

can be upgraded to also include second and third pressure 

levels. Studies569,570,571 show that converting a single pressure 

 

569 "Exergetic and Economic Evaluation of the Effects of HRSG 

Configurations on the Performance of Combined Cycle Power 

Plants." M. Mansouri, et al. Energy Conversion and Management

58:47-58, 2012.

570 "Combined Cycle Power Plant Performance Analyses Based on 

Single-Pressure and Multipressure Heat Recovery Steam 

Generator." M. Raham, Journal of Energy Engineering, 138:136-

145, 2012.
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HRSG with steam reheat to a double pressure configuration with 

steam reheat can reduce the CO2 emission rate of a NGCC unit by 

1.5 to 1.7 percent. These same studies show that converting from 

a single pressure configuration with reheat to a triple pressure 

configuration with reheat can yield a 1.8 to 2 percent reduction 

in the CO2 emission rate. Similarly, units constructed with only 

a double pressure configuration without reheat can obtain a 0.4 

percent reduction by adding a reheat cycle or a 0.9 percent 

reduction by converting to a triple pressure configuration and 

adding a reheat cycle. Existing NGCC turbines that convert to 

these advanced HRSG configurations and that deploy the 

previously discussed combustion turbine and steam turbine 

upgrades can realize CO2 emission rate reductions ranging from 6 

to 10 percent, depending on their baseline design and condition.

Based on the available options to improve the efficiency of 

existing NGCC units and the fact that the vast majority of 

existing NGCC units are already achieving emission rates of 

1,000 lb CO2/MWh-g or less, we have concluded that all 

reconstructed NGCC units can achieve this emission rate.

Finally, we note that an owner or operator that is 

considering reconstructing an existing simple cycle turbine 

 

571 "Thermodynamic Evaluation of Combined Cycle Plants." N. 

Woudstras et al. Energy Conversion and Management 51:1099-1110, 

2010.
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should decide how they wish to operate that turbine in the 

future. If they anticipate operating above the percentage 

electric sales threshold, then they should install a HRSG and 

steam turbine and convert to a NGCC power block in accordance 

with our determination that NGCC is the BSER for base load 

applications. If they intend to operate the turbine below the 

percentage electric sales threshold, however, then the clean 

fuels standard, described below, will apply.

c. Newly constructed and reconstructed non-base load natural 

gas-fired units

The EPA agrees with the commenters who stated that “no 

emission limit” would be inconsistent with the requirements of 

CAA 111(a)(1). We therefore are finalizing an input-based 

standard based on the use of clean fuels for non-base load 

natural gas-fired combustion turbines in recognition that 

efficiency can be reduced due to operation at low loads, 

cycling, and frequent startups. The EPA has concluded that, at 

this time, we do not have sufficient information to set a 

meaningful output-based standard for non-base load natural gasfired combustion turbines. The input-based standard requires

non-base load units to burn fuels with an average emission rate 

of 120 lb CO2/MMBtu or less. This standard is readily achievable 

because the CO2 emission rate of natural gas is 117 lb CO2/MMBtu. 

The most common backup fuel is distillate oil, which has a CO2
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emission rate of 163 lb CO2/MMBtu. A non-base load natural gasfired combustion turbine burning 9 percent distillate oil and 91 

percent natural gas has an emission rate of 121 lb CO2/MMBtu, 

which rounds to 120 lb CO2/MMBtu using two significant digits.

Therefore, the vast majority of owners and operators of natural 

gas-fired non-base load combustion turbines will be able to 

achieve the standard using business-as-usual fuels. 

While the emission reductions that will result from 

restricting the use of fuels with higher CO2 emission rates is 

minor, the compliance burden is also minimal. Owners and 

operators of non-base load natural gas-fired combustion turbines 

burning fuels with consistent chemical compositions that meet 

the clean fuels requirement (e.g., natural gas, ethane, 

ethylene, propane, naphtha, jet fuel kerosene, distillate oils 1 

and 2, and biodiesel) will only need to maintain records that 

they burned these fuels in the combustion turbine. No additional 

recordkeeping or reporting will be required. Owners and 

operators burning fuels with higher CO2 emission rates and/or 

chemical compositions that vary (e.g., residual oil, non-jet 

fuel kerosene, landfill gas) will have to follow the procedures 

in part 98 of this part to determine the average CO2 emission 

rate of the fuels burned during the applicable 12-operatingmonth compliance period and submit quarterly reports to verify 

that they are in compliance with the required emission standard.
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d. Newly constructed and reconstructed multi-fuel-fired units

We also are finalizing an input-based standard based on the 

use of clean fuels, as opposed to an output-based standard, for 

multi-fuel units for several reasons. Specifically, we do not 

currently have continuous CO2 emissions data for multi-fuel-fired

units, we have not evaluated the potential efficiency impacts of 

different fuels, and the range of carbon content of non-natural 

gas fuels complicates establishing an appropriate output-based 

standard. Based on this lack of data, we have concluded that we 

cannot establish an output-based emission standard for multifuel-fired combustion turbines at this time.

The input-based emissions standard for this subcategory is 

based on the use of clean fuels. The use of clean fuels will 

ensure that newly constructed and reconstructed combustion 

turbines minimize CO2 emissions during all periods of operation

by limiting the use of fuels with higher CO2 emission rates. To 

accurately represent the BSER and limit the ability of units to 

co-fire higher CO2 emitting fuels with natural gas, we have 

concluded that it is necessary to use an equation based on the 

heat input from natural gas to determine the applicable emission 

standard. The 12-operating-month standard will vary from 120 lb 

CO2/MMBtu to 160 lb CO2/MMBtu depending on the fraction of heat 

input from natural gas. The standard will be calculated by 

adding the product of the percent of heat input from natural gas 
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and 120 with the product of the heat input from non-natural gas 

fuels and 160. For example, a combustion turbine that burns 80 

percent natural gas and 20 percent distillate oil would be 

subject to an emission standard of 130 lb CO2/MMBtu (rounded to 

two significant figures), which is equivalent to the actual 

emission rate of a unit burning this combination of fuels. On 

the other hand, a combustion turbine that burns 100 percent 

residual oil would be subject to an emission standard of 160 lb 

CO2/MMBtu, but would have a higher actual emission rate, and 

would thus be out of compliance. In this way, the standard will 

restrict higher carbon fuels from being burned in multi-fuelfired units, but will be readily achievable by units burning 

clean fuels. 

According to information submitted to the EIA, the primary, 

non-natural gas fuels used by combustion turbines today for the 

production of electricity should all meet our definition of a 

clean fuel. Thus, while the emission reductions that will result 

from restricting the use of fuels with higher CO2 emission rates 

is minor, the compliance burden is also minimal. Owners and 

operators of multi-fuel-fired combustion turbines burning fuels 

with consistent chemical compositions that meet the clean fuels 

requirement (e.g., natural gas, ethylene, propane, naphtha, jet 

fuel kerosene, distillate oils 1 and 2, and biodiesel) will only 

need to maintain records that they burned these fuels in the 
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combustion turbine. No additional recordkeeping or reporting 

will be required. Owners and operators burning fuels with higher 

CO2 emission rates and/or chemical compositions that vary (e.g., 

residual oil, non-jet fuel kerosene, landfill gas) will have to 

follow the procedures in part 98 of this part to determine the 

average CO2 emission rate of the fuels burned during the 

applicable 12-operating-month compliance period and submit 

quarterly reports to verify that they are in compliance with the

required emission standard.

e. Modified units

The EPA is not finalizing the proposed emission standards 

for stationary combustion turbines that conduct modifications. 

As explained in Section XV below, we are withdrawing the June 

2014 proposal with respect to these sources. We received a 

significant number of comments asserting that modified 

combustion turbines could not meet the proposed emission 

standards of 1,000 lb/MWh-g for large turbines and 1,100 lb/MWhg for small turbines. For the reasons explained in Section 

IX.B.1 above, we have decided not to subcategorize combustion 

turbines based on size for a number of reasons and are setting a 

single standard of 1,000 lb/MWh-g for all base load natural gasfired turbines instead. While we are confident that all new and 

reconstructed units will be able to achieve this standard, we 

are less confident that all smaller combustion turbines that 
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undertake a modification, specifically those that were 

constructed prior to 2000, will be able to do so. Until we have 

the opportunity to further investigate the full range of 

modifications that turbine owners and operators might undertake, 

we consider it premature to finalize emission standards for 

these sources.

Combustion turbines have unique characteristics that make 

determining an appropriate emission standard for modified 

sources a more challenging task than for coal-fired boilers. For 

example, each combustion turbine engine has a specific 

corresponding combustor. The development of more efficient 

combustor upgrades for existing turbine designs typically 

requires manufacturers to expend considerable resources. 

Consequently, not all manufacturers offer combustor upgrades for 

smaller or older designs because it would be difficult to recoup

their investment. In contrast, efficiency upgrades for boilers 

can generally be installed regardless of the specific boiler’s

characteristics. 

In addition, natural gas has the lowest CO2 emission rate 

(in terms of lb CO2/MMBtu) of any fossil fuel. As a result, an 

owner or operator that adds the ability to burn a backup fuel, 

such as distillate oil, to an existing turbine would likely 

trigger an NSPS modification. This is a relatively low-capitalcost upgrade that would significantly increase a unit’s
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potential hourly emission rate, even though the annual emissions 

increase would be relatively minor because operating permits

generally limit the amount of distillate oil that a unit can 

burn. We need to conduct additional analysis to determine an 

appropriate emission standard for units that undertake this type 

of modification, which does not involve any of the combustion 

turbine components that impact efficiency.

To be clear, the EPA is not reaching a final decision that 

modifications should be subject to different requirements than 

we are finalizing in this rule for new and reconstructed 

sources. We have made no decisions, and this matter is not 

concluded. We plan to continue to gather information, consider 

the options for modifications, and develop a new proposal for 

modifications in the future. Therefore, the EPA is withdrawing 

the proposed standards for all combustion turbines that conduct 

modifications and is not issuing final standards for those 

sources at this time. See Section XV below. We note that the 

effect of this withdrawal is that modified combustion turbines 

will continue to be existing sources subject to section 

111(d).572

 

572 As discussed above in Section VI.A of this preamble, a 

modified source that is not covered by a final or pending 

proposed standard continues to be an “existing source” and so 

will be covered by requirements under section 111(d). Under the 

definition of “existing source” in section 111(a)(6), an 
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X. Summary of Other Final Requirements for Newly Constructed, 

Modified, and Reconstructed Fossil Fuel-fired Electric Utility 

Steam Generating Units and Stationary Combustion Turbines

This section describes the final action’s requirements 

regarding startup, shutdown, and malfunction; continuous 

monitoring; emissions performance testing; continuous 

compliance; and notification, recordkeeping, and reporting for 

newly constructed, modified, and reconstructed affected steam 

generating units and combustion turbines. We also explain final 

decisions regarding several of these requirements.

A. Startup, Shutdown, and Malfunction Requirements

In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 

(D.C. Cir. 2008), the D.C. Circuit vacated portions of two 

provisions in the EPA’s CAA section 112 regulations governing 

the emissions of hazardous air pollutants (HAP) during periods 

of startup, shutdown, and malfunction (SSM). Specifically, the 

Court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) 

and 40 CFR 63.6(h)(1), holding that under section 302(k) of the 

 

existing source is any source that is not a new source. Under 

the definition of “new source” in section 111(a)(2), a modified 

source is a new source only if the modification occurs after the 

publication of regulations (or proposed regulations, if earlier) 

that will be applicable to that source. Because we are not 

finalizing regulations with respect to modified steam turbines, 

and are withdrawing the proposal with respect to such sources, 

there are neither final regulations nor pending proposed 

regulations which will be applicable to such modifications. 
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CAA, emissions standards or limitations must be continuous in 

nature and that the SSM exemption violates the CAA's requirement 

that some CAA section 112 standards apply continuously.

Consistent with Sierra Club v. EPA, the EPA has established 

standards in this rule that apply at all times. In establishing 

the standards in this rule, the EPA has taken into account 

startup and shutdown periods and, for the reasons explained 

below as well as in Section V.J.1 above, has not established 

alternate standards for those periods. Specifically, startup and 

shutdown periods are included in the compliance calculation as 

periods of partial load. The final method to calculate 

compliance is to sum the emissions for all operating hours and 

to divide that value by the sum of the electric energy output 

(and useful thermal energy output, where applicable for affected 

CHP EGUs), over a rolling 12-operating-month period. In their 

compliance determinations, sources must incorporate emissions 

from all periods, including startup or shutdown, during which 

fuel is combusted and emissions are being monitored, in addition 

to all power produced over the periods of emissions 

measurements. As explained in Section V.J.1, given that the 

duration of startup or shutdown periods is expected to be small 

relative to the duration of periods of normal operation and that 

the fraction of power generated during periods of startup or 

shutdown is expected to be very small, the impact of these 
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periods on the total average over a 12-operating-month period is 

expected to be minimal.

Periods of startup, normal operations, and shutdown are all 

predictable and routine aspects of a source’s operations. 

Malfunctions, in contrast, are neither predictable nor routine. 

Instead they are, by definition sudden, infrequent and not 

reasonably preventable failures of emissions control, process or 

monitoring equipment. (40 CFR 60.2). The EPA interprets CAA 

section 111 as not requiring emissions that occur during periods 

of malfunction to be factored into development of section 111 

standards. Nothing in CAA section 111 or in case law requires 

that the EPA consider malfunctions when determining what 

standards of performance reflect the degree of emission 

limitation achievable through “the application of the best 

system of emission reduction” that the EPA determines is 

adequately demonstrated. While the EPA accounts for variability 

in setting emissions standards, nothing in CAA section 111 

requires the agency to consider malfunctions as part of that 

analysis. A malfunction should not be treated in the same manner 

as the type of variation in performance that occurs during 

routine operations of a source. A malfunction is a failure of 

the source to perform in a “normal or usual manner” and no 

statutory language compels the EPA to consider such events in 

setting CAA section 111 standards of performance.
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Further, accounting for malfunctions in setting emission 

standards would be difficult, if not impossible, given the 

myriad different types of malfunctions that can occur across all 

sources in the category and given the difficulties associated 

with predicting or accounting for the frequency, degree, and 

duration of various malfunctions that might occur. As such, the 

performance of units that are malfunctioning is not “reasonably” 

foreseeable. See, e.g., Sierra Club v. EPA, 167 F.3d 658, 662 

(D.C. Cir. 1999) (“The EPA typically has wide latitude in 

determining the extent of data-gathering necessary to solve a 

problem. We generally defer to an agency's decision to proceed 

on the basis of imperfect scientific information, rather than to 

'invest the resources to conduct the perfect study.'") See also, 

Weyerhaeuser v Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) (“In 

the nature of things, no general limit, individual permit, or 

even any upset provision can anticipate all upset situations. 

After a certain point, the transgression of regulatory limits 

caused by ‘uncontrollable acts of third parties,’ such as 

strikes, sabotage, operator intoxication or insanity, and a 

variety of other eventualities, must be a matter for the 

administrative exercise of case-by-case enforcement discretion, 

not for specification in advance by regulation.”). In addition, 

emissions during a malfunction event can be significantly higher 

than emissions at any other time of source operation. For 
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example, if an air pollution control device with 99 percent 

removal goes off-line as a result of a malfunction (as might 

happen if, for example, the bags in a baghouse catch fire) and 

the emission unit is a steady state type unit that would take 

days to shut down, the source would go from 99 percent control 

to zero control until the control device was repaired. The 

source’s emissions during the malfunction would be 100 times 

higher than during normal operations. As such, the emissions 

over a 4-day malfunction period would exceed the annual 

emissions of the source during normal operations. As this 

example illustrates, accounting for malfunctions could lead to 

standards that are not reflective of (and significantly less 

stringent than) levels that are achieved by a well-performing, 

non-malfunctioning source. It is reasonable to interpret CAA 

section 111 to avoid such a result. The EPA’s approach to 

malfunctions is consistent with CAA section 111 and is a 

reasonable interpretation of the statute.

Given that compliance with the emission standard is 

determined on a 12-operating-month rolling average basis, the 

impact of periods of malfunctions on the total average over a 

12-operating-month period is expected to be minimal. Thus, 

malfunctions over that period are not likely to result in a 

violation of the standard.
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In the unlikely event that a source fails to comply with 

the applicable CAA section 111 standards as a result of a 

malfunction event, the EPA would determine an appropriate 

response based on, among other things, the good faith efforts of 

the source to minimize emissions during malfunction periods, 

including preventative and corrective actions, as well as root 

cause analyses to ascertain and rectify excess emissions. The 

EPA would also consider whether the source's failure to comply 

with the CAA section 111 standard was, in fact, sudden, 

infrequent, not reasonably preventable and was not instead 

caused in part by poor maintenance or careless operation. 40 CFR 

60.2 (definition of malfunction).

If the EPA determines in a particular case that an 

enforcement action against a source for violation of an emission 

standard is warranted, the source can raise any and all defenses 

in that enforcement action and the federal district court will 

determine what, if any, relief is appropriate. The same is true 

for citizen enforcement actions. Similarly, the presiding 

officer in an administrative proceeding can consider any defense 

raised and determine whether administrative penalties are 

appropriate.

In summary, the EPA interpretation of the CAA and, in 

particular, CAA section 111 is reasonable and encourages 

practices that will avoid malfunctions. Administrative and 
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judicial procedures for addressing exceedances of the standards 

fully recognize that violations may occur despite good faith 

efforts to comply and can accommodate those situations.

In the January 2014 proposal for newly constructed EGUs, 

the EPA had proposed to include an affirmative defense to civil 

penalties for violations caused by malfunctions in an effort to 

create a system that incorporates some flexibility, recognizing 

that there is a tension, inherent in many types of air 

regulation, to ensure adequate compliance while simultaneously 

recognizing that despite the most diligent of efforts, emission 

standards may be violated under circumstances entirely beyond 

the control of the source. Although the EPA recognized that its 

case-by-case enforcement discretion provides sufficient 

flexibility in these circumstances, it included the affirmative 

defense to provide a more formalized approach and more 

regulatory clarity. See Weyerhaeuser Co. v. Costle, 590 F.2d 

1011, 1057-58 (D.C. Cir. 1978) (holding that an informal caseby-case enforcement discretion approach is adequate); but see

Marathon Oil Co. v. EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977) 

(requiring a more formalized approach to consideration of

“upsets beyond the control of the permit holder”). Under the 

EPA’s regulatory affirmative defense provisions, if a source 

could demonstrate in a judicial or administrative proceeding 

that it had met the requirements of the affirmative defense in 
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the regulation, civil penalties would not be assessed. Recently, 

the U.S. Court of Appeals for the District of Columbia Circuit 

vacated an affirmative defense in one of the EPA’s CAA section 

112 regulations. NRDC v. EPA, 749 F.3d 1055 (D.C. Cir., 2014) 

(vacating affirmative defense provisions in CAA section 112 rule 

establishing emission standards for Portland cement kilns). The 

court found that the EPA lacked authority to establish an 

affirmative defense for private civil suits and held that under 

the CAA, the authority to determine civil penalty amounts in 

such cases lies exclusively with the courts, not the EPA. 

Specifically, the Court found: “As the language of the statute 

makes clear, the courts determine, on a case-by-case basis, 

whether civil penalties are ‘appropriate.’” See NRDC at 1063 

(“[U]nder this statute, deciding whether penalties are 

‘appropriate’ in a given private civil suit is a job for the 

courts, not EPA.”).573 In light of NRDC, the EPA is not including 

a regulatory affirmative defense provision in this final rule. 

As explained above, if a source is unable to comply with 

emissions standards as a result of a malfunction, the EPA may 

use its case-by-case enforcement discretion to provide 

 

573 The court’s reasoning in NRDC focuses on civil judicial 

actions. The court noted that “EPA's ability to determine 

whether penalties should be assessed for Clean Air Act 

violations extends only to administrative penalties, not to 

civil penalties imposed by a court.” Id.
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flexibility, as appropriate. Further, as the D.C. Circuit 

recognized, in an EPA or citizen enforcement action, the court 

has the discretion to consider any defense raised and determine 

whether penalties are appropriate. Cf. NRDC, at 1064 (arguments 

that violations were caused by unavoidable technology failure 

can be made to the courts in future civil cases when the issue 

arises). The same is true for the presiding officer in EPA 

administrative enforcement actions.574

B. Continuous Monitoring Requirements

The majority of comments received on the proposal supported 

the EPA's use of existing monitoring requirements under the Acid 

Rain Program, which are contained in 40 CFR part 75 

requirements. In response to this, the EPA is finalizing 

monitoring requirements that incorporate and reference the part 

75 monitoring requirements for the majority of the CO2 and energy 

output monitoring requirements while ensuring accuracy and 

stringency required under the program.

 

574 Although the NRDC case does not address the EPA’s authority 

to establish an affirmative defense to penalties that is 

available in administrative enforcement actions, the EPA is not 

including such an affirmative defense in the final rule. As 

explained above, such an affirmative defense is not necessary. 

Moreover, assessment of penalties for violations caused by 

malfunctions in administrative proceedings and judicial 

proceedings should be consistent. Cf. CAA section 113(e) 

(requiring both the Administrator and the court to take 

specified criteria into account when assessing penalties).
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This final rule requires owners or operators of EGUs that 

combust solid fossil fuel to install, certify, maintain, and 

operate continuous emission monitoring systems (CEMS) to measure 

CO2 concentration, stack gas flow rate, and (if needed) stack gas 

moisture content in accordance with 40 CFR part 75, in order to 

determine hourly CO2 mass emissions rates (tons/hr).

The rule allows owners or operators of affected EGUs that 

burn exclusively gaseous or liquid fuels to install fuel flow 

meters as an alternative to CEMS and to calculate the hourly CO2

mass emissions rates using Equation G-4 in Appendix G of Part 

75. To implement this option, hourly measurements of fuel flow 

rate and periodic determinations of the gross calorific value 

(GCV) of the fuel are also required, in accordance with appendix

D of part 75.

In addition to requiring monitoring of the CO2 mass emission 

rate, the rule requires EGU owners or operators to monitor the 

hourly unit operating time and “gross output”, expressed in 

megawatt hours (MWh). The gross output includes electrical 

output plus any mechanical output, plus 75 percent of any useful 

thermal output.

The rule requires EGU owners or operators to prepare and 

submit a monitoring plan that includes both electronic and hard 

copy components, in accordance with 40 CFR 75.53(g) and (h). The 

electronic portion of the monitoring plan should be submitted to 
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the EPA’s CAMD using the Emissions Collection and Monitoring 

Plan System (ECMPS) Client Tool. The hard copy portion of the 

plan should be sent to the applicable state and EPA Regional 

office. Further, all monitoring systems used to determine the CO2

mass emission rates have to be certified according to 40 CFR

75.20 and section 6 of part 75, appendix A within the 180-day 

window of time allotted under 40 CFR 75.4(b), and are required 

to meet the applicable on-going quality assurance procedures in 

appendices B and D of part 75.

The rule requires all valid data collected and recorded by 

the monitoring systems (including data recorded during startup, 

shutdown, and malfunction) to be used in assessing compliance. 

Failure to collect and record required data is a violation of 

the monitoring requirements, except for periods of monitoring 

system malfunctions, repairs associated with monitoring system 

malfunctions, and required monitoring system quality assurance 

or quality control activities that temporarily interrupt the 

measurement of stack emissions (e.g., calibration error tests, 

linearity checks, and required zero and span adjustments). 

The rule requires only those operating hours in which valid 

data are collected and recorded for all of the parameters in the 

CO2 mass emission rate equation to be used for calculating 

compliance with applicable emission limits. Additionally for 

EGUs using CO2 CEMS, only unadjusted stack gas flow rate values 
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should be used in the emissions calculations. In this rule, part

75 bias adjustment factors (BAFs) should not be applied to the 

flow rate data. These restrictions on the use of part 75 data 

for part 60 compliance are consistent with previous NSPS 

regulations and revisions. Additionally if an affected EGU 

combusts natural gas and/or fuel oil and the CO2 mass emissions 

rate are measured using Equation G-4 in appendix G of part 75, 

then determination of site-specific carbon-based F-factors using 

Equation F-7b in section 3.3.6 of appendix F of part 75 is 

allowed, and use of these Fc values in the emissions calculations 

instead of using the default Fc values in the Equation G-4 

nomenclature is also allowed.

This final rule includes the following special compliance 

provisions for units with common stack or multiple stack 

configurations; these provisions are consistent with 40 CFR

60.13(g):

 If two or more EGUs share a common exhaust stack, are 

subject to the same emission limit, and the operator is 

required to (or elects to) determine compliance using 

CEMS, then monitoring the hourly CO2 mass emission rate at 

the common stack instead of monitoring each EGU separately 

is allowed. If this option is chosen, the hourly gross 

electrical load (or steam load) is the sum of the hourly 

loads for the individual EGUs and the operating time is 
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expressed as “stack operating hours” (as defined in 40 CFR 

72.2). Then, if compliance with the applicable emission 

limit is attained at the common stack, each EGU sharing 

the stack will be in compliance with the CO2 emissions 

limit.

 If the operator is required to (or elects to) determine 

compliance using CEMS and the effluent from the EGU 

discharges to the atmosphere through multiple stacks (or, 

if the effluent is fed to a stack through multiple ducts 

and is monitored in the ducts), then monitoring the hourly 

CO2 mass emission rate and the “stack operating time” at 

each stack or duct separately is required. In this case, 

compliance with the applicable emission limit is 

determined by summing the CO2 mass emissions measured at 

the individual stacks or ducts and dividing by the total 

gross output for the unit. 

The rule requires 95 percent of the operating hours in each 

compliance period (including the compliance periods for the 

intermediate emission limits) to be valid hours, i.e., operating 

hours in which quality-assured data are collected and recorded 

for all of the parameters used to calculate CO2 mass emissions. 

EGU owners or operators have the option to use backup monitoring 

systems, as provided in 40 CFR 75.10(e) and 75.20(d), to help 

meet this data capture requirement. This requirement is separate 
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from the requirement for a source to demonstrate compliance with 

an applicable emission standard. When demonstrating compliance 

with an emission standard the calculation must use all valid 

data to calculate a compliance average even if the percent of 

valid hours recorded in the period is less than the 95 percent 

requirement.

C. Emissions Performance Testing Requirements

Similarly to the comments received on monitoring for the 

proposal, commenters in general supported the use of current 

testing requirements required under the Acid Rain Program 40 CFR 

part 75 requirements. Thus the EPA is finalizing requirements 

for performance testing as consistent with part 75 requirements 

where appropriate to ensure the quality and accuracy of data and 

measurements as required by the final rule.

In accordance with 40 CFR 75.64(a), the final rule requires 

an EGU owner or operator to begin reporting emissions data when 

monitoring system certification is completed or when the 180-day 

window in 40 CFR 75.4(b) allotted for initial certification of 

the monitoring systems expires (whichever date is earlier). For 

EGUs subject to the 1,400 lb CO2/MWh-g) emission standard, the 

initial performance test consists of the first 12 operating 

months of data, starting with the month in which emissions are 

first required to be reported. The initial 12-operating-month 

compliance period begins with the first month of the first 
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calendar year of EGU operation in which the facility exceeds the 

capacity factor applicability threshold.

The traditional 3-run performance tests (i.e., stack tests) 

described in 40 CFR 60.8 are not required for this rule. 

Following the initial compliance determination, the emission 

standard is met on a 12-operating-month rolling average basis. 

D. Continuous Compliance Requirements

Commenters supported the use of a 12-operating-month 

rolling average for the compliance period for the final 

standards. In response, this final rule specifies that 

compliance with the 1,400 lb CO2/MWh-g emission limit is 

determined on a 12-operating-month rolling average basis, 

updated after each new operating month. For each 12-operatingmonth compliance period, quality-assured data from the certified 

Part 75 monitoring systems is used together with the gross 

output over that period of time to calculate the average CO2 mass 

emissions rate. 

The rule specifies that the first operating month included 

in the initial 12-operating-month compliance period is the month 

in which reporting of emissions data is required to begin under 

40 CFR 75.64(a), i.e., either the month in which monitoring 

system certification is completed or the month in which the 180-

day window allotted to finish certification testing expires 

(whichever month is earlier). 
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Initial compliance with the applicable emissions limit in 

kg/MWh is calculated by dividing the sum of the hourly CO2 mass 

emissions values by the total gross output for the 12-operatingmonth period. Affected EGUs continue to be subject to the 

standards and maintenance requirements in the CAA section 111 

regulatory general provisions contained in 40 CFR part 60, 

subpart A.

Several commenters stated that the final rule should 

require operators to round their calculated emissions rates to 

three significant figures when comparing their actual rates to 

the standard. These commenters said that allowing use of only 

two significant digits when calculating the 12-operating-month 

rolling average emission rate would constitute relaxation of the 

standard by 5 percent because an actual emission rate of 1,049.9 

lb CO2/MWh rounds to 1,000 lb of CO2 per MWh when only two

significant figures are required in the final step of compliance 

calculations. Commenters also suggested that the emission limits 

be written in scientific notation (e.g., 1.10 x 10^3 lb CO2/MWh) 

to clarify the number of significant digits that should be used 

when evaluating compliance. Other commenters suggested that the 

final step in compliance calculations should reflect rounding 

the emission rate to the nearest whole number using the ASTM 

rounding convention (ASTM E29). 

The General Provisions of Part 60 specify the rounding 
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conventions for compliance calculations at 40 CFR 60.13(h)(3) 

including the provision that "after conversion into units of the 

standard, the data may be rounded to the same number of 

significant digits used in the applicable subpart to specify the 

emission limit." 

The final rule requires that the 12-operating-month rolling 

average emission rate must be rounded to three significant 

figures if the applicable emissions standard is greater than or 

equal to 1,000 (e.g., an actual emission rate of 1,004.9 lb

CO2/MWh is rounded to 1,000 lb CO2/MWh); for standards of 1000 or 

less, the final rule requires rounding the actual emission rate 

to two significant figures (e.g., an actual emission rate of 

454.9 kg CO2/MWh is rounded to 450 kg CO2/MWh). Historically, 

many of the emissions limits under part 60 have been expressed 

to two significant digits (e.g., the original SO2 emission 

standard for coal-fired units under Subpart D was 1.2 lb

SO2/MMBtu). The rounding conventions under the General Provisions 

allow the reporting of all emission rates in the range from 1.15 

to 1.249 as 1.2 lb SO2/MMBtu. During compliance periods with 

emissions at the lower end of this range, the operator is 

required to report higher emissions than actually occurred; 

during compliance periods at the upper end of this range the 

operator is allowed to report lower emissions than actually 

occurred. In either case the absolute error remains small 
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because the emission rate in this example is a relatively small 

numerical value. In addition, the required emission reductions 

typically are large enough that rounding does not impact the 

emission control strategy of affected units. However, the final 

standards for CO2 emissions include numerical values that are 

larger than many historical emissions standards and require a 

relatively small percent reduction in emissions. Accordingly, it 

is appropriate to require the use of three significant digits 

when completing compliance calculations resulting in numerical 

values larger than 1,000. This is particularly important when 

considering the relatively small emission rate changes that may 

be required for compliance with the unit-specific emission 

standards being finalized for modified steam generating and IGCC 

units because a rounding error of 5 percent may be larger than 

the percent difference between the affected unit's historically 

best emission rate and the emission rate immediately preceding 

the modification.

The final rule requires rounding of emission rates with 

numerical values greater than or equal to 1,000 to three 

significant figures and rounding of rates with numerical values 

less than 1,000 to two significant figures.

E. Notification, Recordkeeping, and Reporting Requirements

Commenters supported the coordination of notification, 

recordkeeping, and reporting required under this rule in 
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conjunction with the requirements already in place under part 

75, so the EPA has made the requirements as efficient and 

streamlined as possible with the current requirements under part 

75. The final rule requires an EGU owner or operator to comply 

with the applicable notification requirements in 40 CFR 75.61, 

40 CFR 60.7(a)(1) and (a)(3), and 40 CFR 60.19. The rule also 

requires the applicable recordkeeping requirements in subpart F 

of part 75 to be met. For EGUs using CEMS, the data elements 

that are recorded include, among others, hourly CO2

concentration, stack gas flow rate, stack gas moisture content 

(if needed), unit operating time, and gross electric generation. 

For EGUs that exclusively combust liquid and/or gaseous fuel(s) 

and elect to determine CO2 emissions using Equation G-4 in 

appendix G of part 75, the key data elements in subpart F that 

are recorded include hourly fuel flow rates, fuel usage times, 

fuel GCV, gross electric generation. 

The rule requires EGU owners or operators to keep records 

of the calculations they perform to determine the total CO2 mass 

emissions and gross output for each operating month. Records of 

the calculations performed to determine the average CO2 mass 

emission rate (kg/MWh) and the percentage of valid CO2 mass 

emission rates in each compliance period are required to be 

kept. The rule also requires sources to keep records of 

calculations performed to determine site-specific carbon-based 
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F-factors for use in Equation G-4 of part 75, appendix G (if 

applicable). 

Sources are required to keep all records for a period of 3

years. All required records must be kept on-site for a minimum 

of two years, after which the records can be maintained offsite. 

The rule requires all affected EGU owners/operators to 

submit quarterly electronic emissions reports in accordance with 

subpart G of part 75. The reports in appendix G that do not 

include data required to calculate compliance with the 

applicable CO2 emission standard are not required to be reported 

under this rule. The rule requires the reports in 40 CFR 60.5555 

to be submitted using the ECMPS Client Tool. Except for a few 

EGUs that may be exempt from the Acid Rain Program (e.g., oilfired units), this is not a new reporting requirement. Sources 

subject to the Acid Rain Program are already required to report 

the hourly CO2 mass emission rates that are needed to assess 

compliance with this rule.

Additionally, in the final rule and as part of an agencywide effort to streamline and facilitate the reporting of 

environmental data, the rule requires selected data elements 

that pertain to compliance under this rule, and that serve the 

purpose of identifying violations of an emission standard, to be 

reported periodically using ECMPS. 
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Specifically, EGU owners/operators must submit quarterly 

electronic reports within 30 days after the end of each quarter 

consistent with current part 75 reporting requirements. The 

first report is for the quarter that includes the final (12th) 

operating month of the initial 12-operating-month compliance 

period. For that initial report and any subsequent report in 

which the 12th operating month of a compliance period (or 

periods) occurs during the calendar quarter, the average CO2 mass 

emissions rate (kg/MWh) is reported for each compliance period, 

along with the dates (year and month) of the first and twelfth 

operating months in the compliance period and the percentage of 

valid CO2 mass emission rates obtained in the compliance period. 

The dates of the first and last operating months in the 

compliance period clearly bracket the period used in the 

determination, which facilitates auditing of the data. Reporting 

the percentage of valid CO2 mass emission rates is necessary to 

demonstrate compliance with the requirement to obtain valid data 

for 95 percent of the operating hours in each compliance period. 

Any violations that occur during the quarter are identified. If 

there are no compliance periods that end in the quarter, a 

definitive statement to that effect must be included in the 

report. If one or more compliance periods end in the quarter but 

there are no violations, a statement to that effect must be 

included in the report. 
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Currently, ECMPS is not programmed to receive the 

additional information included in the report required under 40 

CFR 60.5555(a)(2) for affected EGUs. However, we will make the 

necessary modifications to the system in order to fully 

implement the reporting requirements of this rule upon 

promulgation. 

XI. Consistency between BSER Determinations for This Rule and 

the Rule for Existing EGUs

In the CAA section 111(d) rule for existing steam units and 

combustion turbines that the EPA is promulgating at the same 

time as this CAA section 111(b) rule, the EPA is identifying as 

part of the BSER for those sources, building block 1 (for steam 

units, efficient operation), building block 2 (for steam units, 

dispatch shift to existing NGCC units), and building block 3 

(for steam units and combustion turbines, substitution of 

generation with new renewable energy). In this section, we 

explain why the EPA is not identifying building blocks 1, 2, or 

3 as part of the BSER for new, modified, or reconstructed steam 

generators or combustion turbines. 

A. Newly Constructed Steam Generating Units 

1. Preference for Technological Controls as the BSER for New 

EGUs

As discussed in this preamble and in more detail in the 

preamble to the CAA section 111(d) rule for existing sources, 
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the phrase “system of emission reduction” is undefined and 

provides the EPA with discretion in setting a standard of 

performance under CAA section 111(b) or emission guidelines 

under CAA section 111(d). Because the phrase by its plain 

language does not limit our review of potential systems in 

either context, the same systems could be considered for 

application in new and existing sources. That said, many other 

factors and considerations direct us to focus on different 

systems when establishing a standard of performance under CAA 

section 111(b) and an emission guideline under CAA section 

111(d). Thus, it is useful to describe part of the underlying 

basis for the BSER – partial CCS - that the EPA has determined 

for new steam units before discussing the building blocks that 

form the BSER for existing units. 

For new steam generating units, the EPA is identifying, as 

the BSER, systems of emission reduction that assure that these 

sources are inherently low-emitting at the time of construction. 

The following reasons support this approach to the BSER. 

New sources are expected to have long operating lives over 

which initial capital costs can be amortized. Thus, new 

construction is the preferred time to drive capital investment 

in emission controls. In this case, the BSER for new steam 

generators, partial CCS, requires substantial capital 

expenditures, which new sources are best able to accommodate.
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While CAA section 111(b)(1)(B) and (a)(1) by their terms do 

not mandate that the BSER assure that new sources are inherently 

low emitting, that approach to the BSER is consistent with the 

legislative history.575 See Section III.H.3.b.4 above. For 

instance, the 1970 Senate Committee Report explains that “[t]he 

overriding purpose of this section [concerning new source 

performance standards] would be to prevent new air pollution 

problems, and toward that end, maximum feasible control of new 

sources at the time of their construction is seen by the 

committee as the most effective and, in the long run, the least 

expensive approach.”576 Existing sources, on the other hand, 

would be regulated through emission standards, which were 

broadly understood at the time to reflect available technology, 

alternative methods of prevention and control, alternative 

fuels, processes, and operating methods.577,578

 

575 Although Congress expressed a clear preference that new 

sources would be “designed, built, equipped, operated, and 

maintained so as to reduce emissions to a minimum,” the Senate 

Committee Report also makes clear that the term standard of 

performance “refers to the degree of emission control which can 

be achieved through process changes, operation changes, direct 

emission control, or other methods.” Sen. Rep. No. 91-1196 at 

15-17, 1970 CAA Legis. Hist. at 415-17 (emphasis added). 

576 Sen. Rep. No. 91-1196 at 15-16, 1970 CAA Legis. Hist. at 416 

(emphasis added).

577 See 1970 CAA Amendments, Pub. L. 91-604, § 4, 84 Stat. 1676, 

1679 (Dec. 31, 1970) (describing information that the EPA must 

issue to the states and appropriate air pollution control 

agencies along with the issuance of ambient air quality criteria 
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2. Practical Implications of Including the Building Blocks

Several practical considerations make the building blocks 

inappropriate for new sources. Thus, for the following reasons, 

the EPA does not consider it appropriate to include the building 

blocks as part of the BSER for new sources: 

a. Additional cost

Partial CCS will impose substantial (albeit reasonable) 

costs on new steam-generating EGUs, and, as a result, the EPA 

does not believe that including additional measures as part of 

the BSER would be appropriate. One disadvantage in adding 

additional costs is that doing so would make it more difficult 

for new steam-generating EGUs to compete with new nuclear units. 

Because the BSER is selected after considering cost (among other 

factors), the EPA is not required to,579 and in this case 

 

under Section 4 of the 1970 CAA titled “Ambient Air Quality and 

Emission Standards”).

578 In the 1977 CAA Amendments, Congress revised section 

111(a)(1) to mandate that the EPA base standards for new sources 

on technological controls, but, at the same time, made clear 

that the EPA was not required to base the emission guidelines 

for existing sources on technological controls. In the 1990 CAA 

Amendments, Congress repealed the section 111(a)(1) requirements 

that distinguished between new and existing sources and largely 

restored the 1970 CAA Amendments version of section 111(a)(1).

579 For example, as early as a 1979 NSPS rulemaking for affected 

EGUs, the EPA recognized that it was not required to establish 

as the BSER the most stringent adequately demonstrated system of 

emission reduction available, and instead could weigh the amount 

of additional emission reductions against the costs. See 44 F.R. 

52792, 52798 (Sept. 10, 1979) (“Although there may be emission 

control technology available that can reduce emissions below 
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believes it would not be appropriate to, select the most 

stringent adequately demonstrated system of emission reduction

(through the combination of partial CCS and the building blocks) 

for purposes of setting a standard of performance under CAA 

section 111(b). 

Building block 1 measures are not appropriate (or would be 

redundant) because the BSER for new steam generating units is 

based on highly efficient supercritical technology, i.e., stateof-the-art, efficient equipment. See Section V.K above. 

Accordingly, there is little improvement in efficiency that can 

be justified as part of the BSER.

Building block 2 and 3 measures are not appropriate for the 

BSER because new steam units would have a significantly limited 

range of options to implement building blocks 2 and 3. The new 

source performance standard was proposed and is being finalized 

as a rate-based standard. Thus, if building blocks 2 and 3 were 

included in the BSER, a more stringent rate-based standard would 

be applicable to all new sources. However, it is conceivable 

that the EPA could propose a hybrid standard that would include 

 

those levels required to comply with standards of performance, 

this technology might not be selected as the basis of standards 

of performance due to costs associated with its use. 

Accordingly, standards of performance should not be viewed as 

the ultimate in achievable emission control. In fact, the Act 

requires (or has potential for requiring) the imposition of a 

more stringent emission standard in several situations.”). 
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both an emission-rate limit that reflects partial CCS and a 

requirement for allowances that reflects building blocks 2 and 

3. Accordingly, the following discussion assumes either a ratebased or mass-based standard, or part of a hybrid standard.

In both a rate-based program and a mass-based program, 

building blocks 2 and 3 measures can be implemented through a 

range of methods, including trading with other EGUs. While it is 

not necessarily the case that every existing source will be able 

to implement each of the methods, in general, existing sources 

will have a range of measures to choose from. However, at least 

some of those methods may not be available to new sources, which 

would render compliance with their emission limits more 

challenging and potentially more costly.

One example is emission trading with other affected EGUs. 

For existing sources, emission trading is an important option 

for implementing the building blocks. There are large numbers of 

existing sources, and they will become subject to the section 

111(d) standards of performance at the same time. It may be more 

cost-effective for some to implement the building blocks than 

others, and, as a result, some may over-comply and some may 

under-comply, and the two groups may trade with each other. 

Because of the large numbers of existing sources, the trading 

market can be expected to be robust. Trading optimizes 

efficiency. As a result, existing sources have more flexibility 
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in the overall amount of their investment in building blocks 2 

and 3 and can adjust investment obligations among themselves 

through emissions trading.

In contrast, new sources construct one at a time, and it is 

unknown how many new sources there will be. Without a sizeable 

number of new sources, there will not be a robust trading 

market. Thus, a new source cannot count on being able to find a 

new source trading partner. In addition, it is not possible to 

count on new sources being able to trade with existing sources, 

for several reasons. First, as noted, there are indications in 

the legislative history that new sources should be wellcontrolled at the source, which casts doubt on whether new 

sources should be allowed to meet their standards through the 

purchase of emission credits. Second, new sources must meet 

their standards of performance as soon as they begin operations. 

If they do so before the year 2022, when existing sources become 

subject to section 111(d) state plan standards of performance, 

no existing sources will be available as trading partners. 

In addition, for section 111(d) sources, we are granting a 

7-year period of lead-time for the implementation of the 

building blocks. This is due, in part, to the benefits of 

allowing the ERC and allowance markets to develop. However, the 

new source standards take effect immediately, so new sources 

would not have the advantage of this lead time were they subject 
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to more stringent standards that also reflected the building 

blocks.580

In addition, if there are an unexpectedly large number of 

new sources, then they would be obliged to invest in greater 

amounts of building blocks 2 and 3, and that could reduce the 

amounts of building blocks 2 and 3 available for existing 

sources, and thereby raise the costs of building blocks 2 and 3 

for existing sources. This could compromise the BSER under 

section 111(d) and undermine the ability of existing sources to 

comply with their section 111(d) obligations.581

B. New Combustion Turbines

For new combustion turbines, the building blocks are not 

appropriate as part of the BSER either. Building block 1 is 

limited to steam generating units, and therefore has no 

applicability to new combustion turbines. Measures comparable to 

 

580 At least in theory, we could consider promulgating a standard 

of performance for new affected EGUs that becomes more stringent 

beginning in 7 years, based on a more stringent BSER. We are not 

inclined to adopt that approach because section 111(b)(1)(B) 

requires that we review and, if necessary, revise the section 

111(b) standards of performance no later than every 8 years 

anyway.

581 The EPA is authorized to consider the BSER for new and 

existing sources in conjunction with each other. In the 1977 CAA 

Amendments, Congress revised section 111(a)(1) to require 

technological controls for new combustion sources at least in 

part because this requirement would preclude new sources from 

relying on low-sulfur coal to achieve their emission limits, 

which, in turn, would free up low-sulfur coal for existing 

sources.
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those in building block 1 would not be appropriate because new

highly efficient NGCC construction already entails high 

efficiency equipment and operation. Building block 2 is also 

limited to steam generating units and is not appropriate as part 

of the BSER for new NGCC units because it would not result in 

any emission reductions.

The reasons why building block 3 are not appropriate are 

the same as discussed above for why building blocks 2 and 3 are 

not appropriate for new steam generating units (limited range of 

options for implementation (including lack of availability of 

trading), lack of lead-time for implementation, and the 

possibility of reducing the availability of renewable energy for 

existing sources).

C. Modified and Reconstructed Steam and NGCC Units

For modified and reconstructed steam generators, the EPA 

identified the BSER as maintenance of high efficiency or 

implementation of a highly efficient unit. The resulting 

emission limit must be met over the specified time period and 

cannot be deviated from or averaged. As a result, a modified or 

reconstructed steam generator generally will require ongoing 

maintenance and may find it prudent to operate below its limit 

as a safety margin. This represents a substantial commitment of 

resources. For these units, the additional costs of implementing 

the building blocks would not be appropriate.
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In addition, building block 1 is not appropriate for 

modified or reconstructed steam generating units because the 

BSER for these units is already based on highly efficient 

performance. For the same reasons, it does not make sense to 

attempt to develop the analogue to building block 1 for 

reconstructed NGCC units – the BSER for them, too, is already 

based on highly efficient performance.

Building block 2 is not appropriate for reconstructed NGCC 

units because it would not yield any reductions.

Building blocks 2 and 3 are not appropriate for modified or 

reconstructed steam generators, and building block 3 is not 

appropriate for reconstructed NGCC units, for the same reasons 

that they are not appropriate for new EGUs, as described above

(limited range of options for implementation (including lack of 

availability of trading), lack of lead-time for implementation, 

and the possibility of reducing the availability of renewable 

energy for existing sources).

XII. Interactions with Other EPA Programs and Rules

A. Overview

This final rule will, for the first time, regulate GHGs 

under CAA section 111. In Section IX of the preamble to the 

proposed rule, the EPA addressed how regulation of GHGs under 

CAA section 111 could have implications for other EPA rules and 

for permits written under the CAA Prevention of Significant 
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Deterioration (PSD) preconstruction permit program and the CAA 

Title V operating permit program. The EPA proposed to adopt 

provisions in the regulations that explicitly addressed some of 

these implications.

For purpose of the PSD program, the EPA is finalizing 

provisions in part 60 of its regulations that make clear that 

the threshold for determining whether a PSD source must satisfy 

the BACT requirement for GHGs continues to apply after 

promulgation of this rule. This rule does not require any 

additional revisions to State Implementation Plans. As discussed 

further below, this final rule may have bearing on the 

determination of BACT for new, modified, and reconstructed EGUs 

that require PSD permits. With respect to the Title V operating 

permits program, this rule does not affect whether sources are 

subject to the requirement to obtain a Title V operating permit 

based solely on emitting or having the potential to emit GHGs 

above major source thresholds. However, this rule does have some 

implications for Title V fees, which the EPA is addressing in 

this final rule. 

Finally, the fossil fuel-fired EGUs covered in this rule 

are or will be potentially impacted by several other recently 

finalized or proposed EPA rules, and such potential interactions 

with other EPA rules are discussed below.
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B. Applicability of Tailoring Rule Thresholds under the PSD 

Program

In our January 8, 2014 proposal, the EPA proposed to adopt 

regulatory language in 40 CFR part 60 that would ensure the 

promulgation of this NSPS would not undercut the application of 

rules that limit the application of the PSD permitting program 

requirements to only the largest sources of GHGs. An intervening 

decision of the United States Supreme Court has, to a large 

extent, resolved the legal issue that led the EPA to propose 

these part 60 provisions. The Supreme Court has since clarified 

that the PSD program does not apply to smaller sources based on 

the amount of GHGs they emit. However, because the largest 

sources emitting GHGs remain subject to the PSD permitting 

requirements, the EPA has concluded that it remains appropriate 

to adopt the proposed regulatory provisions in 40 CFR part 60 in 

this rule. We discuss our reasons for this action in detail 

below. 

Under the PSD program in part C of title I of the CAA, in 

areas that are classified as attainment or unclassifiable for 

NAAQS pollutants, a new or modified source that emits any air 

pollutant subject to regulation at or above specified thresholds 

is required to obtain a preconstruction permit. This permit 

assures that the source meets specific requirements, including 

application of BACT to each pollutant subject to regulation 
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under the CAA. Many states (and local districts) are authorized 

by the EPA to administer the PSD program and to issue PSD 

permits. If a state is not authorized, then the EPA issues the 

PSD permits for facilities in that state.

To identify the pollutants subject to the PSD permitting 

program, EPA regulations contain a definition of the term 

“regulated NSR pollutant.” 40 CFR 52.21(b)(50); 40 CFR 

51.166(b)(49). This definition contains four subparts, which 

cover pollutants regulated under various parts of the CAA. The 

second subpart covers pollutants regulated under section 111 of 

the CAA. The fourth subpart is a catch-all provision that 

applies to “[a]ny pollutant that is otherwise subjection to 

regulation under the Act.”

This definition and the associated PSD permitting 

requirements applied to GHGs for the first time on January 2, 

2011, by virtue of the EPA’s regulation of GHG emissions from 

motor vehicles, which first took effect on that same date. 75 FR 

17004 (Apr. 2, 2010). As such, GHGs became subject to regulation 

under the CAA and the fourth subpart of the “regulated NSR 

pollutant” definition became applicable to GHGs.

On June 3, 2010, the EPA issued a final rule, known as the 

Tailoring Rule, which phased in permitting requirements for GHG 

emissions from stationary sources under the CAA PSD and Title V 

permitting programs (75 FR 31514). Under its understanding of 
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the CAA at the time, the EPA believed the Tailoring Rule was 

necessary to avoid a sudden and unmanageable increase in the 

number of sources that would be required to obtain PSD and Title

V permits under the CAA because the sources emitted GHGs

emissions over applicable major source and major modification 

thresholds. In Step 1 of the Tailoring Rule, which began on 

January 2, 2011, the EPA limited application of PSD or Title V 

requirements to sources of GHG emissions only if the sources 

were subject to PSD or Title V “anyway” due to their emissions 

of non-GHG pollutants. These sources are referred to as “anyway 

sources.” In Step 2 of the Tailoring Rule, which began on July 

1, 2011, the EPA applied the PSD and Title V permitting 

requirements under the CAA to sources that were classified as 

major, and, thus, required to obtain a permit, based solely on 

their potential GHG emissions and to modifications of otherwise 

major sources that required a PSD permit because they increased 

only GHG emissions above applicable levels in the EPA 

regulations. 

In the PSD program, the EPA implemented the steps of the 

Tailoring Rule by adopting a definition of the term “subject to 

regulation.” The limitations in Step 1 of the Tailoring Rule are 

reflected in 40 CFR 52.21(b)(49)(iv) and 40 CFR 

51.166(b)(48)(iv). With respect to “anyway sources” covered by 

PSD during Step 1, this provision established that GHGs would 
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not be subject to PSD requirements unless the source emitted 

GHGs in the amount of 75,000 tons per year (tpy) of carbon 

dioxide equivalent (CO2e) or more. The primary practical effect 

of this paragraph is that the PSD BACT requirement does not 

apply to GHG emissions from an “anyway source” unless the source 

emits GHGs at or above this threshold. The Tailoring Rule Step 2 

limitations are reflected in 40 CFR 52.21(b)(49)(v) and 

51.166(b)(48)(v). These provisions contain thresholds that, when 

applied through the definition of “regulated NSR pollutant,” 

function to limit the scope of the terms “major stationary 

source” and “major modification” that determine whether a source 

is required to obtain a PSD permit. See e.g. 40 CFR 

51.166(a)(7)(i) and (iii); 40 CFR 51.166(b)(1); 40 CFR 

51.166(b)(2). 

This structure of the EPA’s PSD regulations created 

questions regarding the extent to which the limitations in the 

Tailoring Rule would continue to apply to GHGs once they became 

regulated, through this final rule, under section 111 of the 

CAA. 79 FR 1487-1488. As discussed above, the definition of 

“regulated NSR pollutant” in the PSD regulations contains a 

separate PSD trigger for air pollutants regulated under the 

NSPS, 40 CFR 51.166(b)(49)(ii) (the “NSPS trigger provision”). 

Thus, when GHGs become subject to a standard promulgated under 

CAA section 111 for the first time under this rule, PSD 
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requirements would presumably apply for GHGs on an additional 

basis besides through the regulation of GHGs from motor 

vehicles. However, the Tailoring Rule, on the face of its 

regulatory provisions, incorporated the revised thresholds it 

promulgated into only the fourth subpart of the PSD definition 

of regulated NSR pollutant (“[a]ny pollutant that otherwise is 

subject to regulation under the Act”). The regulatory text does 

not clearly incorporate the thresholds into the NSPS trigger 

provision in the second subpart (“[a]ny pollutant that is 

subject to any standard promulgated under section 111 of the 

Act”). For this reason, a question arose as to whether the 

Tailoring Rule limitations would continue to apply to the PSD 

requirements after they are independently triggered for GHGs by 

the NSPS that the EPA is now promulgating. Stakeholders 

questioned whether the EPA must revise its PSD regulations –-

and, by the same token, whether states must revise their SIPs –-

to assure that the Tailoring Rule thresholds will continue to 

apply to sources potentially subject to PSD under the CAA based 

on GHG emissions. 

In the January 8, 2014 proposed rule, the EPA explained that 

the agency had included an interpretation in the Tailoring Rule 

preamble, which means that the Tailoring Rule thresholds 

continue to apply if and when the EPA promulgates requirements 

under CAA section 111. 79 FR 1488 (citing 75 FR 31582). 
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Nevertheless, to ensure there would be no uncertainty as to this 

issue, the EPA proposed to adopt explicit language in 40 CFR

60.46Da(j), 40 CFR 60.4315(b), and 40 CFR 60.5515 of the 

agency’s regulations. The proposed language makes clear that the 

thresholds for GHGs in the EPA’s PSD definition of “subject to 

regulation” apply through the second subpart of the definition

of “regulated NSR pollutant” to GHGs regulated under this rule.

The EPA received comments supporting the adoption of this 

proposed language, but several commenters also expressed concern 

that adding this language to part 60 alone would not be 

sufficient. Several commenters urged the EPA to instead revise 

the PSD regulations in parts 51 and 52. In addition, commenters 

expressed concern that further steps were needed to amend the 

SIPs before there would be certainty that the Tailoring Rule 

limitations continued to apply after the adoption of CO2

standards under CAA section 111 in this final rule.

On June 23, 2014, the United States Supreme Court, in Utility 

Air Regulatory Group v. Environmental Protection Agency, issued 

a decision addressing the application of PSD permitting 

requirements to GHG emissions. The Supreme Court held that the 

EPA may not treat GHGs as an air pollutant for purposes of 

determining whether a source is a major source (or modification 

thereof) for the purpose of PSD applicability. The Court also 

said that the EPA could continue to require that PSD permits, 
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otherwise required based on emissions of pollutants other than 

GHGs, contain limitations on GHG emissions based on the 

application of BACT. The Supreme Court decision effectively

upheld PSD permitting requirements for GHG emissions under Step 

1 of the Tailoring Rule for "anyway sources" and invalidated 

application of PSD permitting requirements to Step 2 sources

based on GHG emissions. The Court also recognized that, although

the EPA had not yet done so, it could “establish an appropriate 

de minimis threshold below which BACT is not required for a 

source’s greenhouse gas emissions.” 134 S. Ct. at 2449.

In accordance with the Supreme Court decision, on April 10, 

2015, the U.S. Court of Appeals for the District of Columbia 

Circuit (the D.C. Circuit) issued an amended judgment vacating 

the regulations that implemented Step 2 of the Tailoring Rule, 

but not the regulations that implement Step 1 of the Tailoring 

Rule. The court specifically vacated 40 CFR 51.166(b)(48)(v) and 

40 CFR 52.21(b)(49)(v) of the EPA’s regulations, but did not 

vacate 40 CFR 51.166(b)(48)(iv) or 40 CFR 52.21(b)(48)(iv). The 

court also directed the EPA to consider whether any further 

revisions to its regulations are appropriate in light of UARG v. 

EPA, and, if so, to undertake such revisions. 

The practical effect of the Supreme Court’s clarification of 

the reach of the CAA is that it eliminates the need for Step 2 

of the Tailoring Rule and subsequent steps of the GHG permitting 
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phase in that the EPA had planned to consider under the 

Tailoring Rule. This also eliminates the possibility that the 

promulgation of GHG standards under section 111 could result in 

additional sources becoming subject to PSD based solely on GHGs, 

notwithstanding the limitations the EPA adopted in the Tailoring 

Rule. However, for an interim period, the EPA and the states 

will need to continue applying parts of the PSD definition of 

“subject to regulation” to ensure that sources obtain PSD 

permits meeting the requirements of the CAA.

The CAA continues to require that PSD permits issued to 

“anyway sources” satisfy the BACT requirement for GHGs. Based on 

the language that remains applicable under 40 CFR

51.166(b)(48)(iv) and 40 CFR 52.21(b)(49)(iv), the EPA and 

states may continue to limit the application of BACT to GHG

emissions in those circumstances where a source emits GHGs in 

the amount of at least 75,000 tpy on a CO2e basis. The EPA’s 

intention is for this to serve as an interim approach while the 

EPA moves forward to propose a GHG Significant Emission Rate 

(SER) that would establish a de minimis threshold level for 

permitting GHG emissions under PSD. Under this forthcoming rule, 

the EPA intends to propose restructuring the GHG provisions in 

its PSD regulations so that the de minimis threshold for GHGs

will not reside within the definition of “subject to 

regulation.” This restructuring will be designed to make the PSD 
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regulatory provisions on GHGs universally applicable, without 

regard to the particular subparts of the definition of 

“regulated NSR pollutant” that may cover GHGs. Upon promulgation 

of this PSD rule, it will then provide a framework that states 

may use when updating their SIPs consistent with the Supreme 

Court decision. 

While the PSD rulemaking described above is pending, the 

EPA and approved state, local, and tribal permitting authorities 

will still need to implement the BACT requirement for GHGs. In 

order to enable permitting authorities to continue applying the 

75,000 tpy CO2e threshold to determine whether BACT applies to 

GHG emissions from an “anyway source” after GHGs are subject to 

regulation under CAA section 111, the EPA has concluded that it 

continues to be appropriate to adopt the proposed language in 40 

CFR 60.5515 (subpart TTTT). Because the EPA is not finalizing 

the proposed regulations in subparts Da and KKKK, it is not 

necessary to adopt the comparable provisions that the EPA 

proposed in 40 CFR 60.46Da(j) and 40 CFR 60.4315(b) 

The EPA has evaluated 40 CFR 60.5515 in light of the 

Supreme Court decision and the comments received on the question 

of whether this CAA section 111 standard will undermine the 

application of the Tailoring Rule limitations. While most of the 

Tailoring Rule limitations are no longer needed to avoid 

triggering the requirement to obtain a PSD permit based on GHGs
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alone, the limitation in 40 CFR 51.166(b)(48)(iv) and 40 CFR

52.21(b)(49)(iv) will remain important to provide an interim 

applicability level for the GHG BACT requirement in “anyway 

source” PSD permits. Thus, there continues to be a need to 

ensure that the regulation of GHGs under CAA section 111 does 

not make this BACT applicability level for anyway sources 

effectively inoperable. The language in 40 CFR 60.5515 will 

continue to be effective at avoiding this result after the 

judicial actions described above and the adoption of this final 

rule. The provisions in part 60 reference 40 CFR 51.166(b)(48) 

and 40 CFR 52.21(b)(49) of the EPA’s regulations. However, the 

courts have now vacated 40 CFR 51.166(b)(48)(v) and 40 CFR

52.21(b)(49)(v), and the EPA will take steps soon to eliminate 

these subparts from the CFR. As a result of these steps, the 

language of final 40 CFR 60.5515 will not incorporate the 

vacated parts of 40 CFR 51.166(b)(48) and 40 CFR 52.21(b)(49), 

but these provisions in part 60 will continue to apply to those 

subparts of the PSD rules that are needed on an interim basis to 

limit application of BACT to GHGs only when emitted by an anyway 

source in amounts of 75,000 tpy CO2e or more. Thus, in this final 

rule, the EPA is adopting the proposed text of 40 CFR 60.5515 

for this purpose without substantial change.

As to the concern expressed by some commenters that 

revisions to part 60 alone are not sufficient, the GHG SER 
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rulemaking described above will include proposed revisions to 

the PSD regulations in parts 51 and 52 that should ultimately 

address this concern. The EPA acknowledges that the commenters 

concern will not be fully addressed for an interim period of 

time, but (for the reasons discussed above) the part 60 

provisions adopted in this rule are sufficient to make explicit 

that the 75,000 tpy CO2e BACT applicability level for GHGs will 

apply to GHGs that are subject to regulation under the CAA 

section 111 standards adopted in this rule. 

Rather than adopting a temporary patch in its PSD 

regulations in this rule to address the implications for PSD of 

regulating GHGs under CAA section 111, the EPA believes it will 

be most efficient for the EPA and the states if the EPA 

completes a comprehensive PSD rule that will address all the 

implications of the Supreme Court decision. The revisions the

EPA will consider based on the Supreme Court decision will 

inherently address the commenters concerns about the definition 

of the “subject to regulation” and the proposed part 60 

provisions. To the extent this PSD rule is not complete before 

the EPA proposes additional CAA section 111 standards for GHGs, 

the EPA will need to consider adding provisions like 40 CFR

60.5515 to other subparts of part 60. In a separate rulemaking 

finalized concurrently with this rule, the EPA is also 

finalizing corresponding edits to 40 CFR 60.5705 in Subpart UUUU 
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to clarify that the regulated pollutant is the same for both the 

CAA section 111(b) and section 111(d) rules. As of this time, 

the EPA has not proposed GHG standards for other source 

categories under CAA section 111. To the extent needed, this 

approach of adding provisions to a few subparts in part 60 would 

be less burdensome to states and more efficient than revising 40 

CFR 51.166 at this time solely to address the implications of 

regulating GHGs under CAA section 111. 

The EPA understands that many commenters expressed concern

that PSD SIPs would also have to be amended to address the 

implications of regulating GHGs under CAA section 111. However, 

the language in 40 CFR 60.5515 is designed to avoid the need for 

states to make revisions to the PSD regulations in their SIPs at 

this time. The EPA has previously observed that the form of each 

pollutant regulated under the PSD program is derived from the 

form of the pollutant described in regulations, such as an NSPS, 

that make the pollutant regulated under the CAA. 56 FR 24468, 

24470 (May 30, 1991); 61 FR 9905, 9912-18 (Mar. 12, 1996); 75 FR 

31522. 

Moreover, it is more likely that states would need to 

consider a SIP revision if the EPA were to revise 40 CFR 51.166 

in this rule. Revisions to 51.166 can trigger requirements for 

states to revise their PSD program provisions under 40 CFR

51.166(a)(6). 
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Given the process required in states to review their SIPs 

and submit them to the EPA for approval, it is most efficient 

for all concerned when the EPA is able to consolidate its 

revisions to 40 CFR 51.166. The EPA, thus, believes it will be 

less work for states if we issue a comprehensive set of rules 

addressing regulation of GHGs under the PSD program after the 

Supreme Court decision. 

In comments on the proposed rules, states generally did not 

express concern that the proposed revisions to part 60 were 

insufficient to avoid the need for SIP revisions. In our 

proposal, we addressed any state with an approved PSD SIP 

program that applies to GHGs which believed that this final rule 

would require the state to revise its SIP so that the Tailoring 

Rule thresholds continue to apply. First, the EPA encouraged any 

state that considered such revisions necessary to make them as 

soon as possible. Second, if the state could do so promptly, the 

EPA said it would assess whether to proceed with a separate 

rulemaking action to narrow its approval of that state’s SIP so 

as to assure that, for federal purposes, the Tailoring Rule 

thresholds will continue to apply as of the effective date of 

the final NSPS rule. 79 FR 1487. The EPA did not receive any 

comments or other feedback from states requesting that the EPA 

narrow their program to ensure the Tailoring Rule thresholds 

continue to apply after promulgating this rule. We do not 
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believe such action will be necessary in any state after the 

Supreme Court decision and our action in this rule is to adopt 

the proposed part 60 provisions for purposes of ensuring the 

Step 1 BACT applicability level for GHGs continues to apply on 

an interim basis.

C. Implications for BACT Determinations under PSD

New major stationary sources and major modifications at 

existing major stationary sources are required by the CAA to, 

among other things, obtain a permit under the PSD program before 

commencing construction. The emission thresholds that define PSD 

applicability can be found in 40 CFR parts 51 and 52, and the 

PSD thresholds specific to GHGs are explained in the preceding 

section of this preamble. 

Sources that are subject to PSD must obtain a 

preconstruction permit that contains emission limitations based 

on application of BACT for each regulated NSR pollutant. The 

BACT requirement is set forth in section 165(a)(4) of the CAA, 

and in EPA regulations under 40 CFR parts 51 and 52. These 

provisions require that BACT determinations be made on a caseby-case basis. CAA section 169(3) defines BACT as:

“an emissions limitation (including a visible emission 

standard) based on the maximum degree of reduction for each 

pollutant subject to regulation under the Clean Air Act 

which would be emitted from any proposed major stationary 

source or major modification which the Administrator, on a 

case-by-case basis, taking into account energy, 

environmental, and economic impacts and other costs, 
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determines is achievable for such facility through 

application of production processes and available methods, 

systems, and techniques, including fuel cleaning, clean 

fuels, or treatment or innovative fuel combustion 

techniques for control of each such pollutant....”

Furthermore, this definition in the CAA specifies that 

“[i]n no event shall application of [BACT] result in 

emissions of any pollutants which will exceed the emissions 

allowed by any applicable standard established pursuant to 

section 111 or 112 of the Act.” 

This condition of CAA section 169(3) has historically been 

interpreted to mean that BACT cannot be less stringent than any 

applicable standard of performance under the NSPS. See, e.g., 

U.S. EPA, PSD and Title V Permitting Guidance for Greenhouse 

Gases, EPA-457/B-11-001 (March 2011) (“GHG Permitting Guidance”

or “Guidance”) at 20-21. Thus, upon completion of an NSPS, the 

NSPS establishes a “BACT Floor” for PSD permits that are issued 

to affected facilities covered by the NSPS.

BACT is a case-by-case review that considers a number of 

factors. These factors include the availability, technical 

feasibility, control effectiveness, and the economic, 

environmental and energy impacts of the control option. See GHG

Permitting Guidance at 17-46. The fact that a minimum control 

requirement (i.e., the BACT Floor) is established by the EPA 

through an applicable NSPS does not bar a permitting agency from 

justifying a more stringent control level as BACT for a specific 

PSD permit. 
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It is important to understand how this NSPS may relate to 

determining BACT for new and existing EGUs that require PSD 

permits. PSD generally applies to major sources, while this NSPS 

applies to units that may be within a source. Under this NSPS, 

an affected facility is a new EGU or a modified or reconstructed 

EGU. The new source NSPS requirements apply, in general, to any 

stationary source that adds a new EGU that is an affected 

facility under this NSPS. This could, for example, include a 

proposed brand new (“greenfield”) power plant or an existing 

power plant that proposes to add a new EGU (e.g., to increase

its generating capacity). While this latter scenario is 

considered a “new affected facility” under the NSPS, it is 

generally viewed under PSD as a “modification” of an existing 

stationary source. Thus, the new source NSPS requirements could 

apply to a modification, as that term is defined under PSD. 

In addition, this NSPS will apply to some modified and

reconstructed units, as those terms are defined in this rule and

under part 60. Consequently, this NSPS could establish a BACT 

floor for existing stationary sources that are modifying an 

existing EGU and experience an emissions increase that makes the 

source subject to PSD review. However, a physical change that 

triggers the NSPS modification or reconstruction requirements 

does not necessarily subject the source to PSD requirements, and 

vice versa. In general, in order to trigger the NSPS 
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modification or reconstruction requirements, a physical change 

must increase the maximum hourly emission rate of the pollutant 

(to be an NSPS modification) or the fixed capital cost of the 

change must exceed 50 percent of the fixed capital cost of a 

comparable entirely new facility (to be an NSPS reconstruction). 

See 40 CFR 60.2, 60.14, 60.15. Under the PSD program, however, a 

physical change (or change in the method of operation) must 

result in an increase in annual emissions of the pollutant by a

specified emission threshold in order to be subject to PSD 

requirements. This emission calculation considers the unit’s 

past annual emissions and its projected annual emissions. See, 

e.g., 40 CFR 52.21(a)(2)(iv)(C). In addition, the PSD emissions 

test for a modification allows the existing source to consider 

qualifying emission reductions and increases at the source 

within a contemporaneous period to “net out” of, or avoid, 

triggering PSD review. Thus, it is important to understand the 

differences in how the term “modification” is used in the NSPS 

and PSD programs, and that a physical change that is a 

modification under one program may not necessarily be a 

modification under the other program.

In the preamble to the proposed NSPS for new sources, the 

EPA discussed whether a standard of performance for the new 

source NSPS, specifically the BSER for solid fuel-fired EGUs 

that is based on partial CCS, could become the BACT floor when 
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permitting a modified or reconstructed EGU or non-EGU source. As 

noted above, BACT is a case-specific review by a permitting 

agency. In evaluating BACT, the permitting authority should 

consider all available control technologies that have the 

potential for practical application to the facility or emission 

unit under evaluation. See GHG Permitting Guidance at 24. This 

BACT review must include any technologies that are part of an 

applicable NSPS for the specific type of source and would 

therefore establish the minimum level of stringency for the 

BACT. Thus, it is possible that partial CCS could be considered 

in a BACT review as an available control option for a modified 

or reconstructed EGU facility, or for another type of source 

(e.g., natural gas processing plant), but this NSPS is not an 

applicable standard to such sources so it would not establish a 

requirement that partial CCS is a minimum level of stringency 

for the BACT for those sources. 

Some commenters expressed concern that, if the EPA 

finalizes a BSER for utility boilers and IGCC units that is 

based on partial CCS, it would establish a BACT Floor for new 

EGUs that would be inconsistent with prior BACT determinations 

for EGUs in both permits issued by EPA Regions and permits 

issued by state agencies on which the EPA has commented. Many of 

these comments were more directed at the development and 

deployment of CCS (i.e., the commenter did not believe CCS 
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should be the basis for BSER) rather than examining whether an 

NSPS should establish the BACT floor for applicable sources, 

which is the legal consequence of setting an NSPS under the 

terms of the CAA. Consequently, we respond to these comments in 

other sections of this preamble that support the selection of 

partial CCS as the basis for the BSER for fossil fuel-fired 

electric utility steam generating units.

With regard to the commenters who stated that a BSER for 

EGUs that is based on partial CCS would be inconsistent with 

BACT determinations in previous GHG PSD permits, it is important 

to recognize that a BACT determination is a case-by-case 

analysis and that technological capabilities and costs evolve 

over time.583 In addition, to date the EPA has not issued a PSD 

 

583 In this regard, the 2011 GHG Permitting Guidance states 

that “although CCS is not in widespread use at this time, 

EPA generally considers CCS to be an ‘available’ add-on 

pollution control technology for facilities emitting CO2 in 

large amounts and industrial facilities with high-purity CO2

streams.” GHG Permitting Guidance at 35. The Guidance goes 

on to note that CCS may not be technically feasible at 

modified sources (citing possible issues with “space for CO2

capture equipment at an existing facility”), or in other 

specific circumstances. Id. at 36 (“Logistical hurdles for 

CCS may include obtaining contracts for offsite land 

acquisition ..., the need for funding..., timing of available 

transportation infrastructure, and developing a site for 

secure long term storage. Not every source has the resources 

to overcome the offsite logistical barriers necessary to 

apply CCS technology to its operations, and smaller sources 

will likely be more constrained in this regard”). Id. at 42-

3 EPA also noted that CCS may be expensive in individual 
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permit with GHG BACT for a source that would be an affected 

facility requiring partial CCS under this NSPS (i.e., a fossil

fuel-fired steam generating unit), so one cannot determine 

whether the EPA – as a PSD permitting authority – has been 

either consistent or inconsistent by setting a BSER of partial 

CCS in this NSPS. Although, in the course of a BACT review, some 

permitting authorities may have determined that CCS is not 

technologically feasible or economically achievable for a gasfired EGU, because of the case-by-case nature of the BACT 

analysis it does not automatically follow that the same 

conclusion is appropriate for a solid fuel-fired EGU. 

 

instances and thus eliminated as a control option for that 

reason under step 4 of the BACT analysis, noting further 

that revenues from EOR may offset other costs. Id. at 42-3. 

See also UARG v. EPA, 134 S.Ct. 2427, 2448 (2014) (noting 

that EPA’s GHG Permitting Guidance states that carbon 

capture is reasonably comparable to more traditional, endof-stack BACT technologies, and that petitioners do not 

dispute that).

As explained at Section V.I.5 above, in determining that 

partial CCS is BSER for new fossil fuel steam electric 

plants, the EPA has carefully considered the issue of 

logistics (including cost estimates for land acquisition, 

transportation, and sequestration) and costs generally. Nor 

would new plants face the same types of constraints as 

modified or reconstructed sources in a BACT determination, 

since a new source has more leeway in choosing where to 

site. See text at V.G.3. above. Moreover, the GHG Permitting 

Guidance considered BACT determinations for all types of 

sources, not just those for which the EPA has determined in 

this rule that partial CCS is the BSER, and the concerns 

expressed in the Guidance thus must be considered in that 

broader context.
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Furthermore, PSD permitting requirements first applied to GHGs

in January 2011 and more information about GHG control 

technology has been gained in this four-and-a-half year period. 

Thus, we would expect BACT decisions to evolve as well, such 

that a GHG BACT review for a coal-fired EGU in 2015 may look 

very different from a review that was done in 2011.

Additionally, if a state agency is processing a permit 

application for a solid fuel-fired EGU and does not propose CCS

as BACT (or does not even consider CCS as an available control 

for BACT), the EPA is not necessarily required to comment 

negatively on the draft permit, or to otherwise request or 

require that the state agency amend the BACT to include CCS. For 

state agencies that have their own EPA-approved state 

implementation plan, the state has primacy over their permitting 

actions and discretion to interpret their approved rules and to 

apply the applicable federal and state regulatory requirements 

that are in place at the time for the facility in question. The 

EPA’s role is to provide oversight to ensure that the state 

operates their PSD program in accordance with the CAA and 

applicable rules. If the EPA does not adversely comment on a 

certain draft permit or BACT determination, it does not 

necessarily imply EPA endorsement of the proposed permit or 

determination.
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Some commenters also felt that the determination of partial 

CCS as BSER is inconsistent with the agency’s position on CCS in 

the EPA’s GHG Permitting Guidance, which they say supports the 

notion that additional work is required before CCS can be 

integrated at full-scale electric utility applications. It is 

important to recognize that the EPA’s Permitting Guidance is 

guidance, so it does not contain any final determination of BACT 

for any source. Furthermore, we disagree with the commenters’

characterization of the GHG Permitting Guidance. The Guidance

specifically states “[f]or the purposes of a BACT analysis for 

GHGs, the EPA classifies CCS as an add-on pollution control 

technology that is “available” for facilities emitting CO2 in 

large amounts, including fossil fuel-fired power plants, and for 

industrial facilities with high-purity CO2 streams (e.g., 

hydrogen production, ammonia production, natural gas processing, 

ethanol production, ethylene oxide production, cement 

production, and iron and steel manufacturing). For these types 

of facilities, CCS should be listed in Step 1 of a top-down BACT 

analysis for GHGs.” GHG Permitting Guidance at 32. As discussed 

elsewhere in the Guidance, technologies that should be listed in 

Step 1 are those that “have the potential for practical 

application to the emissions unit and regulated pollutant under 

evaluation.” GHG Permitting Guidance at 24. The EPA continues to 
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stand by its position on the availability of CCS in this 

context, as expressed in the GHG Permitting Guidance.

The GHG Permitting Guidance continues on to discuss casespecific factors and potential limitations with applying CCS, 

and it acknowledges that CCS may not be ultimately selected as 

BACT in “certain cases” based on technology feasibility and 

cost. GHG Permitting Guidance at 36, 43. While acknowledging 

these potential challenges when it was issued in March 2011, the 

Guidance clearly does not rule out the selection of CCS as BACT 

for any source category and it is forward looking. GHG 

Permitting Guidance at 43 (“... as a result of ongoing research 

and development, ... CCS may become less costly and warrant 

greater consideration ... in the future”) Nothing in the Guidance

is inconsistent with EPA’s present position that CCS is 

adequately demonstrated for the types of sources covered by this 

NSPS, as articulated elsewhere in this preamble. 

A commenter asserted that the GHG Permitting Guidance 

should be amended because it calls for consideration of CCS in 

BACT determinations even though the proposed NSPS identified

"partial CCS" as BSER for new boiler and IGCC EGUs. The Guidance

explains that “the purpose of Step 1 of the process is to cast a 

wide net and identify all control options with potential 

application to the emissions unit under review.” GHG Permitting

Guidance at 26. The EPA agrees that the GHG Permitting Guidance 
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only uses the term “CCS” and does not distinguish “partial CCS” 

from “full CCS.” But considering the purpose of Step 1 of the 

process, we believe that the term “CCS”, as it is used in the 

GHG Permitting Guidance, adequately describes the varying levels 

of CO2 capture. A BACT review should analyze all available 

technologies in order to adequately support the BACT 

determination, and may require evaluation of partial CCS, full 

CCS, and/or no CO2 capture. The specific facility type and CO2

capture conditions will dictate the level(s) of CO2 capture that 

are most appropriate to consider as “available” in a BACT 

review. 

D. Implications for Title V Program

Under the Title V program, certain stationary sources, 

including “major sources” are required to obtain an operating 

permit. This permit includes all of the CAA requirements 

applicable to the source, including adequate monitoring, 

recordkeeping, and reporting requirements to assure sources’ 

compliance. These permits are generally issued through EPAapproved state Title V programs.

In the January 8, 2014 proposal, the EPA discussed whether 

this rulemaking would impact the applicability of Title V 

requirements to major sources of GHGs. 79 FR 1489-90. The 

relevant issue for Title V purposes was, in essence, whether 

promulgation of CAA section 111 requirements for GHGs would 
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undermine the Tailoring Rule, which, as explained above, phased 

in permitting requirements for GHG emissions for stationary 

sources under the CAA PSD and Title V permitting programs. Based 

on the EPA’s understanding of the CAA at that time, the proposal 

discussed this issue in the context of the regulatory and 

statutory definitions of “major source,” focusing on revisions 

that had been made in the Tailoring Rule to the definitions in 

the Title V regulations of “major source” and “subject to 

regulation.” 79 FR 1489-90 (quoting 75 FR 31,583). Under the 

Title V regulations, as revised by the Tailoring Rule, “major 

source” is defined to include, in relevant part, “a major 

stationary source ... that directly emits, or has the potential to 

emit, 100 tpy or more of any air pollutant subject to 

regulation.” The proposal further explained that the GHG 

threshold that had been established in the Tailoring Rule had 

been incorporated into the definition of “subject to regulation” 

under 40 CFR 70.2 and 71.2, such that those definitions specify 

“‘that GHGs are not subject to regulation for purposes of 

defining a major source, unless as of July 1, 2011, the 

emissions of GHGs are from a source emitting or having the 

potential to emit 100,000 tpy of GHGs on a CO2e basis.’” Id. 

(quoting 75 FR 31,583). The proposal thus concluded that the 

Title V definition of “major source,” as revised by the 

Tailoring Rule, did not on its face distinguish among types of 
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regulatory triggers for Title V. It further noted that the Title

V program had already been triggered for GHGs, and thus 

concluded that the promulgation of CAA section 111 requirements 

would not further impact Title V applicability requirements for 

major sources of GHGs. 79 FR 1489-90.

As noted elsewhere in this section, after the proposal for 

this rulemaking was published, the United States Supreme Court 

issued its opinion in UARG v EPA, 134 S.Ct. 2427 (June 23, 

2014), and in accordance with that decision, the D.C. Circuit 

subsequently issued an amended judgment in Coalition for 

Responsible Regulation, Inc. v. Environmental Protection Agency, 

Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir., April 10, 

2015). Those decisions support the same overall conclusion as 

the EPA discussed in the proposal, though for different reasons. 

With respect to Title V, the Supreme Court said in UARG v 

EPA that the EPA may not treat GHGs as an air pollutant for 

purposes of determining whether a source is a major source 

required to obtain a Title V operating permit. In accordance 

with that decision, the D.C. Circuit’s amended judgment in 

Coalition for Responsible Regulation, Inc. v. Environmental 

Protection Agency, vacated the Title V regulations under review 

in that case to the extent that they require a stationary source 

to obtain a Title V permit solely because the source emits or 

has the potential to emit GHGs above the applicable major source 
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thresholds. The D.C. Circuit also directed the EPA to consider 

whether any further revisions to its regulations are appropriate 

in light of UARG v. EPA, and, if so, to undertake to make such 

revisions. These court decisions make clear that promulgation of 

CAA section 111 requirements for GHGs will not result in the EPA 

imposing a requirement that stationary sources obtain a Title V 

permit solely because such sources emit or have the potential to 

emit GHGs above the applicable major source thresholds.584

To be clear, however, unless exempted by the Administrator 

through regulation under CAA section 502(a), any source, 

including an area source (a “non-major source”), subject to an

NSPS is required to apply for, and operate pursuant to, a Title

V permit that assures compliance with all applicable CAA 

requirements for the source, including any GHG-related 

applicable requirements. This aspect of the Title V program is 

not affected by UARG v. EPA, as the EPA does not read that 

decision to affect either the grounds other than those described 

 

584 As explained elsewhere in this notice, the EPA intends to 

conduct future rulemaking action to make the appropriate 

revisions to the operating permit rules to respond to the 

Supreme Court decision and the D.C. Circuit’s amended judgment. 

To the extent there are any issues related to the potential 

interaction between the promulgation of CAA section 111 

requirements for GHGs and Title V applicability based on 

emissions above major source thresholds, the EPA expects there 

would be an opportunity to consider those during that 

rulemaking.
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above on which a Title V permit may be required or the 

applicable requirements that must be addressed in Title V 

permits.585 Consistent with the proposal, the EPA has concluded 

that this rule will not affect non-major sources and there is no 

need to consider whether to exempt non-major sources. Thus, 

sources that are subject to the CAA section 111 standards 

promulgated in this rule are required to apply for, and operate 

pursuant to, a Title V permit that assures compliance with all 

applicable CAA requirements, including any GHG-related 

applicable requirements.

E. Implications for Title V Fee Requirements for GHGs

1. Why is the EPA revising Title V fee rules as part of this 

action?

The January 8, 2014 notice of proposed rulemaking (79 FR 

1430)(the “EGU GHG NSPS proposal” or “NSPS proposal”) proposed 

the first section 111 standards to regulate GHGs at EGUs. That 

notice also included proposed revisions to the fee requirements 

of the 40 CFR part 70 and part 71 operating permit rules under 

Title V of the CAA to avoid inadvertent consequences for fees 

 

585 See Memorandum from Janet G. McCabe, Acting Assistant 

Administrator, Office of Air and Radiation, and Cynthia Giles, 

Assistant Administrator, Office of Enforcement and Compliance 

Assurance, to Regional Administrators, Regions 1-10, Next Steps 

and Preliminary Views on the Application of Clean Air Act 

Permitting Programs to Greenhouse Gases Following the Supreme 

Court’s Decision in Utility Regulatory Group v. Environmental 

Protection Agency (July 24, 2014) at 5.
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that would be triggered by the promulgation of the first CAA 

section 111 standard to regulate GHGs. If we do not revise the 

fee rules by the time of the promulgation of the NSPS standards 

for GHGs, then approved part 70 programs implemented by state, 

local and tribal permitting authorities586 that rely on the 

“presumptive minimum” approach and the part 71 program 

implemented by the EPA would be required to account for GHGs in 

emissions-based fee calculations at the same dollar per ton 

($/ton) rate as other air pollutants. The EPA believes this 

would result in the collection of fees in excess of what is 

required to cover the reasonable costs of an operating permit 

program. See NSPS proposal 79 FR 1490.

In response to these concerns, the EPA proposed regulatory 

changes to limit the fees collected based on GHG emissions and 

proposed two fee adjustment options to increase the fees

collected based on the costs for permitting authorities to 

conduct certain review activities related to GHG emissions, 

while still providing sufficient funding for an operating permit 

program. Also, we proposed an option that would have provided 

for no fee adjustments to recover the costs of conducting review 

activities related to GHG emissions. Id. 79 FR 1490. The EPA did 

 

586 Hereafter, for the sake of simplicity, we will generally

refer to part 70 permitting authorities as “state” permitting 

authorities and refer to part 70 programs as “state” programs.
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not propose any action related to state and local permitting 

authorities that do not use the presumptive minimum approach.

Most commenters on the proposal, including state and local 

permitting authorities, were supportive of exempting GHGs from 

the emissions-based fee calculations of the permit rules, but 

support for the fee adjustment options was mixed, with state and 

local permitting authorities generally supporting either of the 

two fee adjustments, and other commenters generally supporting 

the option that provides for no fee adjustment.

2. Background on the Fee Requirements of Title V

In the NSPS proposal, the EPA explained the statutory and 

regulatory background related to the requirement that permitting 

authorities collect fees from the owner or operator of Title V 

sources that are sufficient to cover the costs of the operating 

permit program. CAA section 502(b)(3)(A) requires an operating 

permit program to include a requirement that sources “pay an 

annual fee, or the equivalent over some other period, sufficient 

to cover all reasonable (direct and indirect) costs required to 

develop and administer the permit program.” See also 40 CFR 

70.9(a). CAA section 502(b)(3)(B)(i) requires that, in order to 

have an approvable operating permit program, the permitting 

authority must show “the program will result in the collection, 

in the aggregate, from all sources [required to get an operating 

permit], of an amount not less than $25 per ton of each 
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regulated pollutant [adjusted annually for changes in the 

consumer price index], or such other amount as the Administrator 

may determine adequately reflects the reasonable costs of the 

permit program.” See also 40 CFR 70.9(b)(2). This has been 

generally referred to as the “presumptive minimum” approach. If 

a permitting authority does not wish to use the presumptive 

minimum approach, it may demonstrate “that collecting an amount 

less than the [presumptive minimum amount] will” result in the 

collection of funds sufficient to cover the costs of the 

program. CAA section 503(b)(3)(B)(iv); see also 40 CFR 

70.9(b)(5). This has been generally referred to as the “detailed 

accounting” approach. CAA section 502(b)(3)(B)(ii) sets forth a 

definition of “regulated pollutant” for purposes of calculating 

the presumptive minimum that includes each pollutant regulated 

under section 111 of the CAA. See also 40 CFR 70.2.

3. What fee rules did we propose to revise? 

In the NSPS proposal, to exempt GHGs from emissions-based 

fee calculations, we proposed to exempt GHGs from the definition 

of “regulated pollutant” for purposes of operating permit fee 

calculations (“the GHG exemption”). The EPA then proposed two 

alternative ways to account for the costs of addressing GHGs in 

operating permits through a cost adjustment. First, we proposed 

a modest additional cost for each GHG-related activity of 

certain types that a permitting authority would process (“the 
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GHG adjustment option 1”). Alternatively, we proposed a modest 

additional increase in the per ton rate used in the presumptive 

minimum calculation for all non-GHG fee pollutants (“the GHG 

adjustment option 2”). The EPA also solicited comment on an 

option that would provide no additional cost adjustment to 

account for GHGs (“the GHG adjustment option 3”). All of the GHG 

adjustment options are based on the assumption that the GHG 

exemption is finalized. See NSPS Proposal 79 FR 1493-1495. 

The EPA additionally proposed two clarifications. The first 

was regulatory text in 40 CFR part 60, subparts Da, KKKK and 

TTTT, to clarify that GHGs, as opposed to CO2, is the regulated 

pollutant for fee purposes (“the fee pollutant clarification”). 

Id. at 1505, 1506 and 1511. The second was a proposal to move 

the existing definition of “Greenhouse gases (GHGs)” within 40 

CFR 70.2 and 71.2 to promote clarity in the regulations (“the 

GHG clarification”). Id. 79 FR 1490, 1517, 1518. 

For background purposes, below is a brief summary of each 

of the proposals.

a. The GHG exemption

To address the fee issues discussed in the NSPS proposal, 

the EPA proposed to exempt GHG emissions from the definition of 

“regulated pollutant (for presumptive fee calculation)” in 40 

CFR 70.2 and the definition of “regulated pollutant (for fee 
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calculation)” in 40 CFR 71.2.587 See NSPS preamble 79 FR 1493, 

1495. 

b. The GHG adjustment option 1

The first proposed “GHG adjustment” option (option 1) was 

to include an additional cost for each GHG-related activity of 

certain types that a permitting authority would process (an 

activity-based adjustment). The three activities identified for 

this option were “GHG completeness determination (for initial 

permit or for updated application)” at 43 hours of burden,588

“GHG evaluation for a modification or related permit action” at 

7 hours of burden, and “GHG evaluation at permit renewal” at 10 

hours of burden. See also 79 FR 1494, fn. 280 (providing a 

description of each of these activities). 

For part 70, the burden hours per activity would be 

multiplied by the cost of staff time (in $/hour) specific to the 

state, including wages, benefits, and overhead, to determine the 

cost of each activity. All the activities for a given period 

would be totaled to determine the total GHG adjustment for the 

state. See 79 FR 1494. 

 

587 Hereafter we will refer to these definitions as the “fee 

pollutant” definitions. Also, note that both fee pollutant 

definitions cross-reference the definitions of “regulated air 

pollutant” which includes air pollutants “subject to any 

standard promulgated under section 111 of the Act.”

588 Burden is the hours of staff time necessary to perform a 

task.
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For part 71, we proposed a labor rate assumption of $52 per 

hour in 2011 dollars. Using that labor rate, we proposed to 

determine the GHG fee adjustment for each GHG permitting program 

activity to be a specific dollar amount for each activity (“set 

fees”) that the source would pay for each activity performed. 

See 79 FR 1495. The EPA proposed to revise 40 CFR 70.9(b)(2)(v) 

and 40 CFR 71.9(c)(8) to implement this option.

c. The GHG adjustment option 2

The second proposed GHG adjustment option (option 2) was to 

increase the dollar per ton ($/ton) rates used in the fee 

calculations for each non-GHG fee pollutant. The revised $/ton 

rates would be multiplied by the total tons of non-GHG fee 

pollutants actually emitted by any source to determine the 

applicable total fees. The EPA proposed to increase the $/ton 

rates by 7 percent.589 See NSPS proposal 79 FR 1494, 1495.

d. The GHG adjustment option 3

The EPA also solicited comment on not charging any fees 

related to GHGs (option 3). The basis for this proposed option 

was the observation that most sources that need to address GHGs 

in a permit would also emit non-GHG fee pollutants, and thus, 

 

589 The EPA estimated that both options 1 and 2 would result in 

about a 7 percent increase in the fees collected by operating 

permit programs affected by the proposed rule. For example, the 

presumptive minimum fee rate in effect for September 1, 2014 

through August 31, 2015 is $48.27/ton. A 7 percent increase 

under option 2 would result in a revised fee of $51.65/ton.
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the cost of permitting for any particular source may be 

accounted for adequately without charging any additional fees 

related to GHGs. Id. 79 FR 1494-1495. 

e. The fee pollutant clarification

Another fee-related proposal was to add regulatory text to 

40 CFR part 60, subparts Da, KKKK and TTTT, to clarify that the 

fee pollutant for operating permit purposes would be considered 

to be “GHGs,” (as defined in 40 CFR 70.2 and 71.2),590 rather 

than solely CO2, which would be regulated under the section 111 

standards and implemented through the EGU GHG NSPS. Id. 79 FR

1505, 1506, and 1511.

f. The GHG clarification

The EPA proposed to move the existing definition of 

“Greenhouse gases (GHGs)” within the definition of “Subject to 

regulation” in 40 CFR 70.2 and 71.2 to a separate definition 

within those sections to promote clarity in the regulations. Id.

79 FR 1490, 1517, 1518.

 

590 Note that in 40 CFR §70.2 and §71.2, the term “Greenhouse 

gases (GHGs)” is defined as the “aggregate group of six 

greenhouse gases: carbon dioxide, nitrous oxide, methane, 

hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride.”
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4. What action is the EPA finalizing?

In this action, the EPA is finalizing the following 

elements as proposed: (1) the GHG exemption, (2) the GHG 

adjustment option 1, and (3) the fee pollutant clarification. 

Public commenters on the proposal stated both support and 

opposition to using the NSPS rulemaking action to revise the 

Title V fee rules. Two commenters stated that proposing the 

Title V fee revisions within the NSPS rulemaking would result in 

fewer commenters, particularly state and local permitting 

authorities, having knowledge of the changes to the fee rules

and sufficient opportunity to comment on the changes because the 

NSPS proposal is limited to a single source category, and one 

stated that a separate proposal for the fee rules would provide 

a sufficient opportunity for public comment. The EPA believes it 

is appropriate to move forward with final action amending the 

Title V fee regulations as part of this NSPS. As we explained in 

the preamble for the proposal and elsewhere in this final rule, 

the fee rules and the section 111 standards are interrelated 

because, if we do not revise the fee rules, promulgation of the 

final NSPS will trigger certain requirements related to Title V 

fees for GHG emissions that the EPA believes will result in the 

collection of excessive fees in states that implement the 

presumptive minimum approach and in the part 71 program. Thus, 

it is important to finalize the revisions to the fee rules at 
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the same time or prior to this NSPS, and it is within the EPA’s 

discretion to address the NSPS and the fee rules at the same 

time as part of the same rulemaking action. In response to the 

commenters who were concerned that including the fee rule 

proposal as part of the NSPS proposal would result in the public 

not having sufficient public comment opportunities, the EPA 

believes sufficient public comment opportunities were provided 

on the fee rule changes because the proposal met all public 

participation requirements and we provided additional public 

outreach, including to state and local permitting authorities,

which discussed the fee rule proposal. In addition to the 

publication of the proposed rulemaking in the Federal Register, 

the EPA held numerous hearings, reached out to state partners 

and the public, and developed numerous fact sheets and other 

information to support public comment on this rule. The EPA has 

complied with the applicable public participation requirements 

and executive orders. The proposal met all the requirements for 

public notice – it contained a clear and detailed explanation of 

how the part 70 and 71 rules would be affected by the 

promulgation of the CAA section 111 standard for EGUs and how 

the EPA proposed to revise the related regulatory provisions. We 

received many comments on the proposal to revise the fee rule 

for operating permits programs, and we are taking those comments 

into consideration in the finalization of the rulemaking action.
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a. The GHG exemption

The EPA is taking final action to revise the definition of 

regulated pollutant (for presumptive fee calculation) in 40 CFR 

70.2 and regulated pollutant (for fee calculation) in 40 CFR 

71.2 to exempt GHG emissions. This regulatory amendment will 

have the effect of excluding GHG emissions from being subject to 

the statutory ($/ton) fee rate set for the presumptive minimum 

calculation requirement of part 70 and the fee calculation 

requirements of part 71. We received supportive comments from 

the majority of public commenters, including state and local 

permitting authorities and others, on revising the operating 

permit rules to exempt GHGs from the emission-based calculations 

that use the statutory fee rates. We are finalizing this portion 

of the proposal for the same reasons we explained in the 

proposal notice, including that leaving these regulations 

unchanged would have resulted in the collection of fee revenue 

far beyond the reasonable costs of an operating permit program. 

The EPA believes that these revisions (in conjunction with the 

GHG adjustment, see below) are consistent with the CAA 

requirements for fees pursuant to the authority of section 

502(b)(3)(B)(i).

Some members of the public opposed the proposed GHG 

exemption for reasons including that it may limit permitting 

authorities’ ability to charge sufficient fees to cover the cost 
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of GHG permitting591 if the state is barred from exceeding 

minimum requirements set by the EPA. Despite this adverse 

comment, the EPA believes it is appropriate to finalize the GHG 

exemption because we are not finalizing any requirements that 

would require states to charge any particular fees to any 

particular sources. The changes we are finalizing to part 70 

concern the presumptive minimum approach, which sets a minimum 

fee target for states that have decided to follow the 

presumptive minimum approach. Neither the statute nor the final 

rule require any state following the presumptive minimum 

approach (or any other approach) to charge fees to sources using 

any particular method. Thus, the GHG exemption will not limit 

states’ ability to structure their individual fee programs 

however they see fit in order to meet the requirement that they 

collect revenue sufficient to cover all reasonable costs of 

their permitting program. See CAA section 502(b)(3); 40 CFR 

70.9(b)(3).

b. The GHG adjustment option 1

The EPA is finalizing GHG adjustment option 1 because we 

believe it will result in a system for the calculation of costs 

for part 70 and fees for part 71 that is most directly related 

 

591 We use the term “GHG permitting” in this section of the 

notice to refer to measures undertaken by permitting authorities 

to ensure that GHGs and any applicable requirements related to 

GHGs are appropriately addressed in Title V permitting.
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to the costs of GHG permitting. The EPA has determined that some 

adjustment to cost and fee accounting is important because the 

recent addition of GHG emissions to the operating permitting 

program does add new burdens for permitting authorities. 

Although GHG adjustment option 3 (no GHG permitting fee 

adjustments) was supported by many industrial commenters, the 

EPA rejected it because it is in tension with the statutory 

requirement that permitting authorities collect sufficient fees 

to cover all the reasonable costs of permitting. See CAA section

502(b)(3)(A). Some state and local permitting authorities 

provided comments supporting option 1, while others supported

option 2, and some supported either option, stating no 

preference. Also, a few state and local permitting authorities 

supported finalizing no adjustment and a few others asked for 

flexibility to set fee adjustments not proposed by the EPA, but 

that they believed would be appropriate for their program. 

The EPA is finalizing option 1 instead of option 2 because 

the option 1 adjustments are based on the actual costs for 

permitting authorities to process specific actions that require 

GHG reviews. The option 2 approach, which would have added a 7 

percent surcharge to the $/ton rate used in the fee-related 

calculations, may have been administratively easier to 

implement, but is tied to the emissions of non-GHG air 
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pollutants, which are not directly related to the costs of GHG 

permitting.

Consistent with CAA section 502(b)(3)(B)(i), the 

Administrator has determined that the final rule’s approach of 

exempting GHG emissions from fee-related calculations and 

accounting for the GHG permitting costs through option 1 will 

result in fees that will cover the reasonable costs of the 

permitting programs. 

The EPA is revising the part 70 regulations through this 

final action, specifically 40 CFR 70.9(b)(2), to modify the 

presumptive minimum approach to add the activity-based cost of 

GHG permitting activities, outlined in the revised 40 CFR 

70.9(b)(2)(v), to the emissions-based calculation of 40 CFR 

70.9(b)(2)(i), which is being revised to now exclude GHG 

emissions. To determine the activity-based GHG adjustment under 

40 CFR 70.9(b)(2)(v), the permitting authority will multiply the 

burden hours for each activity (set forth in the regulation) by 

the cost of staff time (in $ per hour), including wages, 

benefits, and overhead, as determined by the state, for the 

particular activities undertaken during the particular time 

period. 
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States that implement the presumptive minimum approach will 

need to follow the final rule’s option 1 approach.592 States that 

use the detailed accounting approach are not directly affected 

by this rulemaking, but they must ensure that their fee 

collection programs are sufficient to fully fund all reasonable 

costs of the operating permit program, including costs 

attributable to GHG-related permitting. The EPA suggests states 

that use the detailed accounting approach consider the 7 percent 

assumption for the costs of GHG permitting in any such analysis, 

consistent with the EPA analysis of options 1 and 2 in the 

proposal.

Consistent with 40 CFR 70.4(i), a state that wishes to 

change its operating permit program as a result of this final 

rule must apprise the EPA. The EPA will review the materials 

submitted concerning the change and decide if a formal program 

revision process is needed and will inform the state of next 

steps. The communication apprising the EPA of any such changes 

should include at least a narrative description of the change 

and any other information that will assist the EPA in its 

 

592 A presumptive minimum state may require various changes to 

its approved operating permit program before it may begin to 

implement the option 1 approach. For example, its regulations, 

and/or program procedures and practices, may need to be revised, 

depending on the structure of the fee provisions in the state’s 

program; thus, the exact response necessary to address this 

final action may vary from state to state.
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assessment of the significance of the changes. Certain changes, 

such as switching from the presumptive minimum method to a 

detailed accounting method, will be considered substantial 

program revisions and be subject to the requirements of 40 CFR 

70.4(i)(2).

With respect to the part 71 program, in this final action 

the EPA is revising 40 CFR 71.9(c) to require each part 71 

source to pay an annual fee which is the sum of the activitybased fee of 40 CFR 71.9(c)(8) and the emissions-based fee of 40 

CFR 71.9(c)(1)-(4)

593, which excludes GHG emissions. To determine 

the activity-based fee, the revised 40 CFR 71.9(c)(8) requires 

the source to pay a “set fee” for each listed activity that has 

been initiated since the fee was last paid. Under part 71, fees 

are typically paid at the time of initial application submittal, 

and thereafter, annually on the anniversary of the initial fee 

payment, or on any other dates that may be established in the 

permit. These set fees would not change until such time as we 

may revise our part 71 rule to change the set fees. 

 

593 Note that the emissions-based fee calculation differs 

somewhat depending on whether the part 71 program is being 

implemented by the EPA (see 40 CFR §71.9(c)(1)); a state, local 

or tribal agency with delegated authority from the EPA (see 

§71.9(c)(2)); the EPA with contractor assistance (see 

§71.9(c)(3)); or an agency with partial delegation authority 

(see §71.9(c)(4)).
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The final rule implements the option 1 approach by listing 

three activities performed by permitting authorities that 

involve GHG reviews. The following describes the activities as 

described in our proposal and certain clarifications we are 

making in the final rule to ensure consistent implementation.

The EPA is finalizing that the first listed activity under 

option 1 is “GHG completeness determination (for initial permit 

or updated application).” This activity must be counted for each 

new initial permit application, even for applications that do 

not include GHGs emissions or applicable requirements, since an 

important part of any completeness determination will be to 

determine that GHG emissions and applicable requirements have 

been properly addressed, as needed, in the application. The fee 

for this activity is a one-time charge that covers the initial 

application and any supplements or updates. The EPA believes 

that a single charge for a GHG completeness determination will 

be adequate to cover the reasonable costs for a permitting 

authority to review an initial application and any subsequent 

application updates related to initial permit issuance; thus, 

any updates to an initial application are included in a single 

“GHG completeness determination,” rather than as a separate 

activity for which the source would be charged in addition to 

the completeness determination for the initial application. This 

is an important distinction because many sources submit multiple 
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permit application updates, either voluntarily or as required by 

the permitting authority, during application review, many of 

which do not require a separate or comprehensive completeness 

determination.

The EPA is finalizing regulatory text that would describe 

the second listed activity as “GHG evaluation for a permit 

modification or related permit action.”594 The EPA had proposed 

that the second listed activity under option 1 would be “GHG 

evaluation for a modification or related permit action.” For the 

final rule, we are clarifying that we are adding a cost for a 

“permit modification” rather than for a “modification.” The term 

“modification” may be interpreted to refer to any change at a 

source, even a change that would not be required to be processed 

as a “permit modification,” while “permit modification” refers 

to any revision to an operating permit that cannot be processed 

as an administrative permit amendment and thus requires a review 

by a permitting authority as either a significant or minor 

permit modification.

 

594 The EPA notes that the term “permit modification” in this 

context refers to all significant permit modifications and minor 

permit modifications under operating permit rules, but not to 

“administrative permit amendments,” as such amendments are not 

defined as “permit modifications” in the permit rules. See, 

e.g., 40 CFR §§70.7(d), (e), and (f).
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The EPA is finalizing the third activity as “GHG evaluation 

at permit renewal.” This activity covers the processing of all 

permit renewal applications and will involve evaluations of 

whether any GHG applicable requirements are properly included.

Some members of the public commented that finalizing a GHG 

adjustment would inappropriately increase sources’ financial 

burdens. The EPA has explained, both in the proposal notice and 

elsewhere in this preamble, the importance of the fee-related 

revisions to account for the costs associated with GHG-related 

permitting. The EPA believes that the revisions being finalized 

will result in modest and reasonable fee increases necessary to 

cover states' increased costs.595 To the extent that commenters 

intended to argue that the adjustments we proposed would exceed 

the actual costs of GHG permitting, no commenters provided any 

information or analysis to support that position. Some 

commenters did state that the costs associated with GHG-related 

permitting should be minimal because few applicable requirements 

will apply to GHGs. As stated earlier in this notice, the EPA’s 

cost estimate for the proposal concerned the incremental costs 

of GHG permitting for any source, not just those that would 

 

595 The EPA estimated in the proposal that option 1 would result 

in about a 7 percent overall increase in the annual part 70 fees 

that are collected by all permitting authorities nationally. See 

79 FR 1494.
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have, at the time of the analysis, triggered the requirement to 

get a permit based on GHG emissions or applicable requirements.

Despite some comments received to the contrary, the EPA 

does not believe it is appropriate to delay the finalization of 

the GHG adjustment. The EPA does not believe such delays would 

be consistent with CAA section 502(b)(3)(A) because states have 

been incurring costs attributable to GHG permitting for several 

years now and increased fees must be collected to cover the 

increased costs. The regulatory changes being finalized in this 

action provide the states with optimal flexibility and 

sufficient funding to implement their GHG permitting programs. 

Some commenters had specifically stated that the EPA should 

delay finalization of this rule until the completion of the next

ICR renewal process. While we do not believe delaying this rule 

is appropriate, as explained above, the EPA notes that we remain 

committed to collecting and analyzing additional data on costs 

attributable to GHG permitting for operating permit programs. We 

may adjust the GHG cost adjustments in future rulemakings if 

necessary to comply with the requirements of the Act.

As an alternative to the options proposed by the EPA, some 

commenters asserted that the EPA should make a GHG cost 

adjustment using a separate, but reduced fee rate ($/ton) for 

GHGs. We, however, believe that the option 1 approach of the 

final rule will be more equitable for sources and more 
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representative of actual costs because option 1 considers the 

costs of the actual permitting activities performed by a 

particular permitting authority, while any emissions-based 

approach would not be as directly related to actual costs 

incurred by permitting authorities.

Some commenters alleged that the EPA’s proposal on 

adjustments to the operating permit programs was vague. The EPA 

provided a thorough discussion of our rationale in the proposal, 

including the basis for the GHG adjustments, and we proposed 

regulatory text to implement our proposal. We explained in the 

proposal that support for the cost adjustment for GHGs under 

option 1 is contained in several analyses performed by the EPA 

and approved by the OMB related to the effect of the addressing 

GHG requirements in operating permits. These analyses have been 

placed in the docket for this rulemaking. The analyses include: 

the Regulatory Impact Assessment (RIA) for the Tailoring Rule 

(see Regulatory Impact Analysis for the Final Prevention of 

Significant Deterioration and Title V Greenhouse Gas Tailoring 

Rule, Final Report, May 2010); the part 70 ICR change request 

for the Tailoring Rule (which was based on the RIA for the 

Tailoring Rule); and the current ICR for part 70 (EPA ICR number 

1587.12; OMB control number 2060–0243). 

Several commenters asked that we make changes to the option 

1 approach that we proposed, such as adding new activities or 
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decreasing the costs we assumed for the proposal. In response to 

these comments, we note that we received no quantitative data or 

other information from commenters that we believe demonstrates 

the need to revise the list of activities we included under 

option 1 or the burden hour assumptions under option 1 for the 

activities. Note that to promote consistent implementation of 

the final option 1 approach, the preamble describes elsewhere a 

few clarifications concerning the activities under option 1 and 

one minor revision to the regulatory text of one of the 

activities.

Since the EPA’s proposed rulemaking, the Supreme Court 

decided in UARG v. EPA that the EPA may not treat GHGs as an air 

pollutant for purposes of determining whether a source is a 

major source required to obtain a Title V operating permit.596

The EPA’s review of the effect of the Supreme Court decision on 

the burden hour assumptions for the GHG review activities under 

proposed option 1 is that the effects are not significant enough 

 

596 The EPA does not, however, read the UARG decision to affect 

other grounds on which a Title V permit may be required or the 

applicable requirements that must be addressed in Title V 

permits. See Memorandum from Janet G. McCabe, Acting Assistant 

Administrator, Office of Air and Radiation, and Cynthia Giles, 

Assistant Administrator, Office of Enforcement and Compliance 

Assurance, to Regional Administrators, Regions 1-10, Next Steps 

and Preliminary Views on the Application of Clean Air Act 

Permitting Programs to Greenhouse Gases Following the Supreme 

Court’s Decision in Utility Regulatory Group v. Environmental 

Protection Agency (July 24, 2014) at 5.
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to warrant revision of the burden hour assumptions in the final 

rule. Proposed option 1 was based on the assumption that 

permitting authorities would need to evaluate all permit 

applications for initial permit issuance, significant and minor 

permit modifications, and permit renewals for GHG issues (even 

if there are no applicable GHG requirements). Even after the 

UARG v. EPA decision, permitting authorities will continue to 

need to evaluate GHG issues for sources applying for a title V 

permit and for permit modifications and renewals for existing 

permits, and we do not anticipate that the decision will

significantly affect the total number of such evaluations that 

will occur in any given year compared to the assumptions in our 

analysis, which as explained above, were based on the 

incremental costs of GHG permitting for any source. Thus, we are 

finalizing the burden hour assumptions as they were proposed. 

See NSPS proposal at 1494 and the supporting statement for the 

2012 part 70 ICR renewal. Also, as discussed previously, we 

remain committed to collecting and analyzing additional data on 

costs and we may adjust the burden hour assumptions or other 

aspects of option 1 in a future rulemaking, if needed.

c. The fee pollutant clarification

We are also finalizing the proposed addition of text within 

40 CFR part 60, subpart TTTT, to clarify that the fee pollutant 

for operating permit purposes is GHG (as defined in 40 CFR 70.2 
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and 71.2). We are finalizing these provisions to add clarity to 

our regulations and to avoid the potential need for possible

future rulemakings to adjust the title V fee regulations if any 

constituent of GHG, other than CO2, becomes subject to regulation 

under section 111 for the first time. The proposal was to add 

this clarifying text to 40 CFR part 60, subparts Da, KKKK and 

TTTT. The final rule adds the clarification text only to subpart 

TTTT because the EPA is codifying all of the requirements for 

the affected EGUs in a new subpart TTTT and including all CO2

emission standards for the affected EGUs (electric utility steam 

generating units, as well as natural gas-fired stationary 

combustion turbines) in that newly created subpart. See Section

III.B of this preamble for more on this subject.

d. The GHG clarification

The EPA is taking no action at this time on the proposal to 

move the definitions of “Greenhouse gases (GHG)” within the 

definition of “Subject to regulation” in 40 CFR parts 70 and 71. 

No public comments were received on this proposed clarification; 

however, subsequent to the proposal, on June 23, 2014, the 

Supreme Court in UARG v. EPA decided that GHG emissions could 

not be used in making certain applicability determinations under 

the operating permit rules. More specifically with respect to 

title V, as described above, the Supreme Court said that the EPA 

may not treat GHGs as an air pollutant for purposes of 
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determining whether a source is a major source required to 

obtain a title V operating permit. In accordance with the 

Supreme Court decision, on April 10, 2015, the D.C. Circuit 

issued an amended judgment in Coalition for Responsible 

Regulation, Inc. v. Environmental Protection Agency, Nos. 09-

1322, 10-073, 10-1092 and 10-1167 (D.C. Cir. April 10, 2015), 

which, among other things, vacated the title V regulations under 

review in that case to the extent that they require a stationary 

source to obtain a title V permit solely because the source 

emits or has the potential to emit GHGs above the applicable 

major source thresholds. The D.C. Circuit also directed the EPA 

to consider whether any further revisions to its regulations are 

appropriate in light of UARG v. EPA, and, if so, to undertake to 

make such revisions. 

In response to the Supreme Court decision and the D.C. 

Circuit’s amended judgment, the EPA intends to conduct future 

rulemaking action to make the appropriate revisions to the 

operating permit rules. As part of any such future rulemaking 

action, the EPA may consider finalizing the proposal to move the 

definitions of GHGs within the operating permit rules.

F. Interactions with Other EPA Rules

Fossil fuel-fired EGUs are, or potentially will be, 

impacted by several other recently finalized or proposed EPA 
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rules.597 Many of the rules that impact fossil fuel-fired EGUs 

apply to existing facilities as well as newly constructed, 

modified, or reconstructed facilities. In fact, the rules 

described below are more applicable to existing EGUs than to 

newly constructed, modified, or reconstructed EGUs. Although 

those rules will affect EGUs as existing sources, because we 

expect that there will be few NSPS modifications or 

reconstructions, we don’t anticipate those rules affecting EGUs 

as modified or reconstructed sources. In constructing new EGUs, 

sources can take all applicable requirements of the various 

rules into consideration. 

1. Mercury and Air Toxics Standards (MATS)

On February 16, 2012, the EPA issued the MATS rule (77 FR 

9304) to reduce emissions of toxic air pollutants from new and 

existing coal- and oil-fired EGUs. The MATS rule will reduce 

emissions of heavy metals, including mercury (Hg), arsenic (As), 

chromium (Cr), and nickel (Ni); and acid gases, including 

hydrochloric acid (HCl) and hydrofluoric acid (HF). These toxic 

air pollutants, also known as hazardous air pollutants or air 

toxics, are known to cause, or suspected of causing, damage 

 

597 We discuss other rulemakings solely for background purposes. 

The effort to coordinate rulemakings is not a defense to a 

violation of the CAA. Sources cannot defer compliance with 

existing requirements because of other upcoming regulations.
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nervous system damage, cancer, and other serious health effects.

The MATS rule will also reduce SO2 and fine particle pollution, 

which will reduce particle concentrations in the air and prevent 

thousands of premature deaths and tens of thousands of heart 

attacks, bronchitis cases and asthma episodes. 

New or reconstructed EGUs (i.e., sources that commence 

construction or reconstruction after May 3, 2011) subject to the 

MATS rule are required to comply by April 16, 2012 or upon 

startup, whichever is later.

Existing sources subject to the MATS rule were required to 

begin meeting the rule’s requirements on April 16, 2015. 

Controls that will achieve the MATS performance standards are 

being installed on many units. Certain units, especially those 

that operate infrequently, may be considered not worth investing 

in given today’s electricity market, and are closing. The final 

MATS rule provided a foundation on which states and other 

permitting authorities could rely in granting an additional, 

fourth year for compliance provided for by the CAA. States 

report that these fourth year extensions are being granted. In 

addition, the EPA issued an enforcement policy that provides a 

clear pathway for reliability-critical units to receive an 

administrative order that includes a compliance schedule of up 
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to an additional year, if it is needed to ensure electricity 

reliability.598

2. Cross-State Air Pollution Rule (CSAPR)

The CSAPR requires states to take action to improve air 

quality by reducing SO2 and NOX emissions that cross state lines. 

These pollutants react in the atmosphere to form fine particles 

and ground-level ozone and are transported long distances, 

making it difficult for other states to attain and maintain the 

NAAQS. The first phase of CSAPR became effective on January 1, 

2015, for SO2 and annual NOX, and May 1, 2015, for ozone season 

NOX. The second phase will become effective on January 1, 2017, 

for SO2 and annual NOX, and May 1, 2017, for ozone season NOX. 

Many of the power plants participating in CSAPR have taken 

actions to reduce hazardous air pollutants for MATS compliance 

 

598 Following promulgation of the MATS rule, industry, states and 

environmental organizations challenged many aspects of the EPA's 

threshold determination that regulation of EGUs is "appropriate 

and necessary" and the final standards regulating hazardous air 

pollutants from EGUs. The U.S. Court of Appeals for the D.C. 

Circuit upheld all aspects of the MATS rule. White Stallion 

Energy Center v. EPA, 748 F.3d 1222 (D.C. Cir. 2014). The 

decision was unanimous on all issues except a dissent was filed 

because the EPA did not consider cost when determining 

regulation of EGUs is appropriate. In Michigan v. EPA, case no. 

14-46, the Supreme Court reversed the D.C. Circuit decision 

upholding the MATS rule finding that EPA erred by not 

considering cost when determining that regulation of EGUs was 

"appropriate" pursuant to section 112(n)(1). The Supreme Court 

considered only the narrow question of cost and did not review 

the other holdings of the D.C. Circuit, nor did the Supreme 

Court vacate the MATS rule.
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that will also reduce SO2 and/or NOX. In this way these two rules 

are complementary. Compliance with one helps facilities comply 

with the other.

3. Requirements for Cooling Water Intake Structures at Power 

Plants (316(b) Rule)

On May 19, 2014, the EPA issued a final rule under section 

316(b) of the Clean Water Act (33 U.S. Code section 1326(b))

(referred to hereinafter as the 316(b) rule.) The rule was 

published on August 15, 2014 (79 FR 48300; August 15, 2014), and 

became effective October 14, 2014. The 316(b) rule establishes 

new standards to reduce injury and death of fish and other 

aquatic life caused by cooling water intake structures at 

existing power plants and manufacturing facilities.599 The 316(b) 

rule subjects existing power plants and manufacturing facilities 

that withdraw in excess of 2 million gallons per day (MGD) of 

cooling water, and use at least 25 percent of that water for 

cooling purposes, to a national standard designed to reduce the 

number of fish destroyed through impingement and entrainment. 

Existing sources subject to the 316(b) rule are required to 

comply with the impingement requirements as soon as practicable 

 

599 CWA section 316(b) provides that standards applicable to 

point sources under sections 301 and 306 of the Act must require 

that the location, design, construction and capacity of cooling 

water intake structures reflect the best technology available 

for minimizing adverse environmental impacts.
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after the entrainment requirements are determined. They must 

comply with applicable site-specific entrainment reduction 

controls based on the schedule of requirements established by 

the permitting authority. Additional information regarding the 

316(b) rule for existing sources is included in Section IX.C of 

the preamble to the CAA section 111(d) emission guidelines for 

existing EGUs that the EPA is finalizing simultaneously with 

this rule. Although the recently issued 316(b) rule discussed 

here applies to existing sources, there are also 316(b) 

technology-based standards for new sources with cooling water 

intake structures.

4. Disposal of Coal Combustion Residuals from Electric Utilities 

(CCR Rule)

On December 19, 2014, the EPA issued the final rule for the 

disposal of coal combustion residuals from electric utilities. 

The rule provides a comprehensive set of requirements for the 

safe disposal of coal combustion residuals (CCRs), commonly 

known as coal ash, from coal-fired power plants. The CCR rule 

establishes technical requirements for existing and new CCR 

landfills and surface impoundments under Subtitle D of the 

Resource Conservation and Recovery Act (RCRA), the nation's 

primary law for regulating solid waste. New CCR landfills and 

surface impoundments are required to meet the technical criteria 

before any CCR is placed into the unit. Existing CCR surface 
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impoundments and landfills are subject to implementation 

timeframes established in the rule for the individual technical 

criteria. For additional information regarding the CCR rule, see 

Section IX.C of the preamble to the CAA section 111(d) emission 

guidelines for existing EGUs that the EPA is finalizing along

with this rule. 

5. Steam Electric Effluent Limitation Guidelines and Standards 

(SE ELG Rule)

The EPA is reviewing public comments and working to 

finalize the proposed SE ELG rule which will impact fossil fuelfired EGUs. In 2013, the EPA proposed the SE ELG rule (78 FR 

34432; June 7, 2013) to strengthen the controls on discharges 

from certain steam electric power plants by revising technologybased effluent limitations guidelines and standards for the 

steam electric power generating point source category. The

proposed regulation, which includes new requirements for both 

existing and new generating units, would reduce impacts to human 

health and the environment by reducing the amount of toxic 

metals and other pollutants currently discharged to surface 

waters from power plants. The EPA intends to take final action 

on the proposed rule by September 30, 2015. Section IX.C of the 

preamble to the CAA section 111(d) emission guidelines for 

existing EGUs that the EPA is finalizing simultaneously with 
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this rule includes additional information regarding the SE ELG 

rule.

The EPA recognizes the importance of assuring that each of 

the rules described above can achieve its intended environmental 

objectives in a commonsense, cost-effective manner, consistent 

with underlying statutory requirements, and while assuring a 

reliable power system. Executive Order (EO) 13563, “Improving 

Regulation and Regulatory Review,” issued on January 18, 2011, 

states that “[i]n developing regulatory actions and identifying 

appropriate approaches, each agency shall attempt to promote... 

coordination, simplification, and harmonization. Each agency

shall also seek to identify, as appropriate, means to achieve 

regulatory goals that are designed to promote innovation.” 

Within the EPA, we are paying careful attention to the 

interrelatedness and potential impacts on the industry, 

reliability and cost that these various rulemakings can have. 

As discussed in earlier sections of this preamble, the EPA 

has identified potential alternative compliance pathways for 

affected newly constructed, modified, and reconstructed fossil 

fuel-fired steam generating units. We are finalizing an emission 

standard for newly constructed highly efficient fossil fuelfired steam generating units that can be met by capturing and 

storing approximately 16 to 23 percent of the CO2 produced from 

the facility or by utilizing other technologies such as natural 
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gas co-firing. For a subcategory of steam generating units that 

conduct “large” modifications according to definitions in this 

final rule, we are finalizing an emission standard that is based 

on a unit-specific emission limitation consistent with each 

modified unit’s best one-year historical performance and can be 

met through a combination of best operating practices and 

equipment upgrades. For reconstructed steam generating units, 

the EPA is finalizing standards of performance based on the 

performance of the most efficient generation technology 

available, which we concluded is the use of the best available 

subcritical steam conditions for small units and the use of 

supercritical steam conditions for large units. The standards 

can also be met through other technology options such as natural 

gas co-firing. In light of these potential alternative 

compliance pathways, we believe that sources will have ample 

opportunity to coordinate their response to this rule with any 

obligations that may be applicable to affected EGUs as a result 

of the MATS, CSAPR, 316(b), SE ELG and CCR rules, all of which 

are or soon will be final rules — and to do so in a manner that 

will help reduce cost and ensure reliability, while also 

ensuring that all applicable environmental requirements are 

met.

600

 

600 It should be noted that regulatory obligations imposed upon 
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The EPA is also endeavoring to enable EGUs to comply with 

applicable obligations under other power sector rules as 

efficiently as possible (e.g., by facilitating their ability to 

coordinate planning and investment decisions with respect to 

those rules) and, where possible, implement integrated 

compliance strategies. Section IX.C of the preamble to the CAA 

section 111(d) emission guidelines for existing EGUs that the 

EPA is finalizing simultaneously with this rule describes such 

an example with respect to the SE ELG and CCR rules.

In light of the compliance flexibilities we are offering in 

this action, we believe that sources will have ample opportunity 

to use cost-effective regulatory strategies and build on their 

longstanding, successful records of complying with multiple CAA, 

CWA, and other environmental requirements, while assuring an 

adequate, affordable, and reliable supply of electricity.

XIII. Impacts of this Action

As explained in the “Regulatory Impact Analysis for the 

Standards of Performance for Greenhouse Gas Emissions for New, 

Modified, and Reconstructed Stationary Sources: Electric Utility 

Generating Units” (EPA-452/R-15-005, August 2015) (RIA), 

 

states and sources operate independently under different 

statutes and sections of statutes; the EPA expects that states 

and sources will take advantage of available flexibilities as 

appropriate, but will comply with all relevant legal 

requirements.
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available data indicate that, even in the absence of the 

standards of performance for newly constructed EGUs, existing 

and anticipated economic conditions will lead electricity 

generators to choose new generation technologies that will meet 

the standards without installation of additional controls. 

Therefore, based on the analysis presented in Chapter 4 of the 

RIA, the EPA projects that this final rule will result in 

negligible CO2 emission changes, quantified benefits, and costs 

on owners and operators of newly constructed EGUs by 2022.601

This conclusion is based on the EPA’s own modeling as well as 

projections by EIA. While the primary conclusion of the analysis 

presented in the RIA is that the standards for newly constructed 

EGUs will result in negligible costs and benefits, the EPA has 

also performed several illustrative analyses that show the 

potential impacts of the rule if certain key assumptions were to 

change. This includes an analysis of the impacts under a range 

of natural gas prices and the costs and benefits associated with 

building an illustrative coal-fired EGU with CCS. These are 

presented in Chapter 5 of the RIA.

As also explained in the RIA for this final rule, the EPA 

also expects that few sources will trigger either the NSPS 

modification or reconstruction provisions that we are finalizing 

 

601 Conditions in the analysis year of 2022 are represented by a 

model year of 2020.
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in this rule. In Chapter 6 of the RIA, we discuss factors that 

limit our ability to quantify the costs and benefits of the 

standards for modified and reconstructed sources.

A. What are the air impacts?

As explained immediately above, the EPA does not anticipate 

that this final rule will result in notable CO2 emission changes 

by 2022 as a result of the standards of performance for newly 

constructed EGUs. The owners of newly constructed EGUs will 

likely choose technologies, primarily NGCC, which meet the 

standards even in the absence of this rule due to existing 

economic conditions as normal business practice.

As also explained immediately above, the EPA expects few 

EGUs to trigger the NSPS modification or reconstruction 

provisions in the period of analysis. 

New steam generating EGUs that choose to comply with the 

final standard of performance by implementing partial postcombustion CCS are likely to use commercially-available aminebased capture systems. Some concern has been raised regarding 

emissions of amines and amine degradation by-products (e.g., NH3) 

from the capture process. To reduce the amine emissions, MHI 

introduced the first optimized washing system within an absorber 

column in 1994, and developed a proprietary washing system in 

2003. In that system, a proprietary reagent is added to the 

water washing section to capture amine impurities such as amine, 
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degraded amine, ammonia, formaldehyde, acetaldehyde, carbonic 

acids and nitrosamines.602 MHI has continued to improve this 

technology for further reduction of amine emissions and 

established an “advanced amine emission reduction system”.

Research performed by MHI at Alabama Power’s Plant Barry 

indicated that an increasing SO3 content in the flue gas caused a 

significant increase of amine emissions. During testing, at 

Plant Barry, MHI applied its proprietary washing system and 

confirmed that the amine emission were drastically reduced.603

Others have also studied emissions and control strategies and 

have determined that a conventional multi-stage water wash and 

mist eliminator at the exit of the CO2 scrubber is effective at 

removal of gaseous amine and amine degradation products 

emissions.604,605 Additional research continues in this area.

B. Endangered Species Act

 Consistent with the requirements of section 7(a)(2) of the 

Endangered Species Act (ESA), the EPA has also considered the 

 

602 Sharma, S.; Azzi, M.; “A critical review of existing 

strategies for emission control in the monoethanolamine-based 

carbon capture process and some recommendations for improved 

strategies”, Fuel, 121, 178 (2014).

603 Kamijo, T.; et al., “SO3 Impact on Amine Emission and Emission 

Reduction Technology”, Energy Procedia, Volume 37, 1793 (2013).

604 Sharma, S. (2014).

605 Mertens, J.; et al., “Understanding ethanolamine (MEA) and 

ammonia emissions from amine based post combustion carbon 

capture: Lessons learned from field tests”, Int’l J. of GHG 

Control, 13, 72 (2013).
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effects of this rule and has reviewed applicable ESA 

regulations, case law, and guidance to determine what, if any, 

impact there may be to listed endangered or threatened species 

or the designated critical habitat of such species and whether 

consultation with the U.S. Fish and Wildlife Service (FWS) 

and/or National Marine Fisheries Service (together, the 

Services) is required by the ESA. Section 7(a)(2) of the ESA 

requires federal agencies, in consultation with the Service(s),

to ensure that actions they authorize, fund, or carry out are 

not likely to jeopardize the continued existence of federally 

listed endangered or threatened species or result in the 

destruction or adverse modification of designated critical 

habitat of such species. 16 U.S.C. 1536(a)(2). Under relevant 

implementing regulations, ESA section 7(a)(2) applies only to 

actions where there is discretionary federal involvement or 

control. 50 CFR 402.03. Further, under the regulations 

consultation is required only for actions that “may affect” 

listed species or designated critical habitat. 50 CFR 402.14. 

Consultation is not required where the action has no effect on 

such species or habitat. Under this standard, it is the federal 

agency taking the action that evaluates the action and 

determines whether consultation is required. See 51 FR 19926, 

19949 (June 3, 1986). Effects of an action include both the 

direct and indirect effects that will be added to the 
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environmental baseline. 50 CFR 402.02. Direct effects are the 

direct or immediate effects of an action on a listed species or 

its habitat.606 Indirect effects are those that are “caused by 

the proposed action and are later in time, but still are 

reasonably certain to occur.” Id. To trigger the consultation 

requirement, there must thus be a causal connection between the 

federal action, the effect in question, and the listed species, 

and if the effect is indirect, it must be reasonably certain to 

occur.

 The EPA notes that the projected environmental effects of 

this final action are positive: reductions in overall GHG 

emissions, and reductions in PM and ozone-precursor emissions 

(SOX and NOX). The EPA recognizes that beneficial effects to 

listed species can, as a general matter, result in a “may 

affect” determination under the ESA. However, the EPA’s 

assessment that the rule will have an overall net positive 

environmental effect by virtue of reducing emissions of certain 

air pollutants does not address whether the rule may affect any 

listed species or designated critical habitat for ESA section 

7(a)(2) purposes and does not constitute any finding of effects 

 

606 See Endangered Species Consultation Handbook, U.S. Fish & 

Wildlife Service and National Marine Fisheries Service at 4-

25(March 1998) (providing examples of direct effects: e.g., 

driving an off road vehicle through the nesting habitat of a 

listed species of bird and destroying a ground nest; building a 

housing unit and destroying the habitat of a listed species).
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for that purpose. The fact that the rule will have overall 

positive effects on the national and global environment does not 

mean that the rule may affect any listed species in its habitat 

or the designated critical habitat of such species within the 

meaning of ESA section 7(a)(2) or the implementing regulations 

or require ESA consultation. 

The EPA notes that the emission reductions achieved by the 

rule are projected to be minor. See Section XIII.F and G. below, 

and RIA chapter 4. Although the final rule imposes substantial 

controls on CO2 emissions, we project few if any new fossil fuelfired steam generating units to be built. Emissions reductions 

from turbines are likewise projected to be minimal. Moreover, we 

reasonably project that capacity additions during the analysis 

period out to 2022 would already be compliant with the rule’s 

requirements (e.g., natural gas combined cycle units, low 

capacity factor natural gas combustion turbines, and small 

amounts of coal-fired units with CCS supported by federal and 

state funding). See RIA chapter 4. 

With respect to the projected GHG emission reductions, the 

EPA does not believe that such minor reductions trigger ESA 

consultation requirements under section 7(a)(2). In reaching 

this conclusion, the EPA is mindful of significant legal and 

technical analysis undertaken by FWS and the U.S. Department of 

the Interior (DOI) in the context of listing the polar bear as a 
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threatened species under the ESA. In that context, in 2008, FWS 

and DOI expressed the view that the best scientific data 

available were insufficient to draw a causal connection between 

GHG emissions and effects on the species in its habitat.

607 The 

DOI Solicitor concluded that where the effect at issue is 

climate change, proposed actions involving GHG emissions cannot 

pass the “may affect” test of the section 7 regulations and thus 

are not subject to ESA consultation. 

The EPA has also previously considered issues relating to 

GHG emissions in connection with the requirements of ESA section 

7(a)(2) and has supplemented DOI’s analysis with additional 

consideration of GHG modeling tools and data regarding listed 

species. The EPA evaluated this same issue in the context of the 

light duty vehicle GHG emission standards for model years 2012-

2016 and 2017-2025. There the agency projected GHG emission 

reductions many orders of magnitude greater over the lifetimes 

of the model years in question608 and, based on air quality 

modeling of potential environmental effects, concluded that “EPA 

knows of no modeling tool which can link these small, time-

 

607 See, e.g., 73 FR 28212, 28300 (May 15, 2008); Memorandum from 

David Longly Bernhardt, Solicitor, U.S. Department of the 

Interior re: ‘‘Guidance on the Applicability of the Endangered 

Species Act’s Consultation Requirements to Proposed Actions 

Involving the Emission of Greenhouse Gases’’ (Oct. 3, 2008).

608 See 75 FR at 25438 Table I.C 2–4 (May 7, 2010); 77 FR at 

62894 Table III–68 (Oct. 15, 2012).
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attenuated changes in global metrics to particular effects on 

listed species in particular areas. Extrapolating from global 

metric to local effect with such small numbers, and accounting 

for further links in a causative chain, remain beyond current 

modeling capabilities.” EPA, Light Duty Vehicle Greenhouse Gas 

Standards and Corporate Average Fuel Economy Standards, Response 

to Comment Document for Joint Rulemaking at 4-102 (Docket EPAOAR-HQ-2009-4782). The EPA reached this conclusion after 

evaluating issues relating to potential improvements relevant to 

both temperature and oceanographic pH outputs. The EPA's 

ultimate finding was that “any potential for a specific impact 

on listed species in their habitats associated with these very 

small changes in average global temperature and ocean pH is too 

remote to trigger the threshold for ESA section 7 (a)(2).”Id.

The EPA believes that the same conclusions apply to the present 

action, given that the projected CO2 emission reductions are far 

less than those projected for either of the light duty vehicle 

rules. See, e.g., Ground Zero Center for Non-Violent Action v. 

U.S. Dept. of Navy, 383 F. 3d 1082, 1091-92 (9th Cir. 2004) 

(where the likelihood of jeopardy to a species from a federal 

action is extremely remote, ESA does not require consultation).

The EPA’s conclusion is entirely consistent with DOI’s analysis 
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regarding ESA requirements in the context of federal actions 

involving GHG emissions.609

The EPA received a comment on the proposal referencing a 

prior letter sent to the EPA by three U.S. Senators,610 which 

asserted that the rule will cause a shift to alternative sources 

of energy such as wind and solar and that such facilities may 

have impacts on listed species. The comment inquired regarding 

ESA consultation in connection with the rule. We reiterate that 

no consultation is required for a rule without potential for a 

specific impact on listed species in their habitats.

C. What are the energy impacts?

This final rule is not anticipated to have a notable effect 

on the supply, distribution, or use of energy. As previously 

stated, the EPA believes that electric power companies will 

 

609 The EPA has received correspondence from Members of Congress 

asserting that the Services have identified several listed 

species affected by global climate change. The EPA’s assessment 

of ESA requirements in connection with the present rule does not 

address whether global climate change may, as a general matter, 

be a relevant consideration in the status of certain listed 

species. Rather, the requirements of ESA section 7(a)(2) must be 

considered and applied to the specific action at issue. As 

explained above, the EPA’s conclusion that ESA section 7(a)(2) 

consultation is not required here is premised on the specific 

facts and circumstances of the present rule and is fully 

consistent with prior relevant analyses conducted by DOI, FWS, 

and the EPA.

610 See Letter from David Vitter, James M. Inhofe, and Mike 

Crapo, United States Senate Committee on Environment and Public 

Works, to Gina McCarthy, Administrator, U.S. Environmental 

Protection Agency, and Dan Ashe, Director, U.S. Fish and 

Wildlife Service, dated March 6, 2014.
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choose to build new EGUs that comply with the regulatory 

requirements of this rule even in its absence, primarily NGCC 

units, because of existing and expected market conditions. As 

also previously stated, the EPA expects few EGUs to trigger the 

NSPS modification or reconstruction provisions in the period of 

analysis.

D. What are the water and solid waste impacts?

This final rule is not anticipated to have notable impacts 

on water or solid waste. As we have noted, the EPA believes that 

utilities and project developers will choose to build new EGUs 

that comply with the regulatory requirements of this rule even 

in its absence, primarily through the construction of new NGCC 

units. As also previously stated, the EPA expects few EGUs to 

trigger the NSPS modification or reconstruction provisions in 

the period of analysis. Still there are expected to be a small 

number of coal plants with CCS and the use of CCS systems 

(especially post-combustion system) will increase the amount of 

water used at the facility. If those plants utilize partial CCS 

to meet the final standard of performance (i.e., approximately 

16 to 23 percent capture), the increased water use will not be 
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significant. See Section V.O.2. The EPA is unaware of any solid 

waste impact resulting from this rule.611

E. What are the compliance costs?

For steam generating EGUs, the EPA has carefully analyzed 

the costs of meeting the promulgated standard of performance for 

a highly efficient SCPC using partial CCS and found these costs 

to be reasonable. See Sections V.H and I above. This analysis 

assumes new capacity not otherwise compliant with the standards 

would be constructed. Based on the analysis in chapter 4 of the 

RIA, the EPA believes the standards of performance for newly 

constructed EGUs will have no notable compliance costs, because 

electric power companies are expected to build new EGUs that 

comply with the regulatory requirements of this final rule even 

in the absence of the rule, primarily NGCC units, due to 

existing and expected market conditions. While the EPA’s 

analysis and projections from EIA continue to show that the rule 

is likely to result in negligible costs and benefits due to 

existing generation choices, the EPA recognizes that some 

companies may choose to construct coal or other fossil fuelfired units and has set standards for these units accordingly.

 

611 Estimated costs for the rule include costs for fly ash and 

bottom ash disposal and for spent solvent recovery and handling. 

See “Cost and Performance Baseline for Fossil Energy Plants 

Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity, 

Revision 3”, DOE/NETL-2015/1723 (July 2015) at pp. 43, 130.
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For this reason, the RIA also analyzes project-level costs of a 

unit with and without CCS, to quantify the potential cost for a 

fossil fuel-fired unit with CCS. 

In addition, the EPA believes the standards of performance 

for modified and reconstructed EGUs will have minimal associated 

compliance costs, because, as previously stated, the EPA expects 

few EGUs to trigger the NSPS modification or reconstruction 

provisions in the period of analysis. 

F. What are the economic and employment impacts?

The EPA does not anticipate that this final rule will 

result in notable CO2 emission changes, energy impacts, monetized 

benefits, costs, or economic impacts by 2022 as a result of the 

standards of performance for newly constructed EGUs. The owners 

of newly constructed EGUs will likely choose technologies that 

meet the standards even in the absence of this rule, due to 

existing economic conditions as normal business practice. 

Likewise, the EPA believes this rule will not have any impacts 

on the price of electricity, employment or labor markets, or the 

U.S. economy. See RIA chapter 4.6.612

As previously stated, the EPA anticipates few units will 

 

612 The employment analysis in the RIA is part of the EPA’s 

ongoing effort to “conduct continuing evaluations of potential 

loss or shifts of employment which may result from the 

administration or enforcement of [the Act]” pursuant to CAA 

section 321(a).
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trigger the NSPS modification or reconstruction provisions. As 

with the new source standards, the EPA does not expect 

macroeconomic or employment impacts as a result of the 

standards.

G. What are the benefits of the final standards?

We are not projecting direct monetized climate benefits in 

terms of CO2 emission reductions associated with these standards 

of performance. This is because, as stated above, the EPA 

believes that electric power companies will choose to build new 

EGUs that comply with the regulatory requirements of this rule 

even in its absence, primarily NGCC units, because of existing 

and expected market conditions. See RIA chapter 4. Moreover, a 

cost-reasonable standard is, in fact, what will drive new 

technology deployment and provide a path forward for new coalfired capacity. See Section V.L above.

As also previously stated, the EPA anticipates few units 

will trigger the NSPS modification or reconstruction provisions. 

In Chapter 6 of the RIA, we discuss factors that limit our 

ability to quantify the costs and benefits of the standards for 

modified and reconstructed sources.

XIV. Statutory and Executive Order Reviews

Additional information about these Statutory and Executive 

Orders can be found at http://www2.epa.gov/lawsregulations/laws-and-executive-orders.
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A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review

This final action is a significant regulatory action that 

was submitted to the Office of Management and Budget (OMB) for 

review. It is a significant regulatory action because it raises 

novel legal or policy issues arising out of legal mandates. Any 

changes made in response to OMB recommendations have been 

documented in the established dockets for this action under 

Docket ID No. EPA-HQ-OAR-2013-0495 (Standards of Performance for 

Greenhouse Gas Emissions from New Stationary Sources: Electric 

Utility Generating Units) and Docket ID No. EPA-HQ-OAR-2013-0603 

(Carbon Pollution Standards for Modified and Reconstructed 

Stationary Sources: Electric Utility Generating Units). The EPA 

prepared an economic analysis of the potential costs and 

benefits associated with this action. This analysis, which is 

contained in the “Regulatory Impact Analysis for the Standards 

of Performance for Greenhouse Gas Emissions for New, Modified, 

and Reconstructed Stationary Sources: Electric Utility 

Generating Units” (EPA-452/R-15-005, August 2015), is available 

in both dockets.

 The EPA does not anticipate that this final action will 

result in any notable compliance costs. Specifically, we believe 

that the standards for newly constructed fossil fuel-fired EGUs
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(electric utility steam generating units and natural gas-fired 

stationary combustion turbines) will have negligible costs 

associated with it over a range of likely sensitivity conditions 

because electric power companies will choose to build new EGUs 

that comply with the regulatory requirements of this action even 

in the absence of the action, because of existing and expected 

market conditions. (See the RIA for further discussion of 

sensitivities). The EPA does not project any new coal-fired 

steam generating units without CCS to be built in the absence of 

this action. However, because some companies may choose to 

construct coal or other fossil fuel-fired EGUs, the RIA also 

analyzes project-level costs of a unit with and without CCS, to 

quantify the potential cost for a fossil fuel-fired EGU with 

CCS.

The EPA also believes that the standards for modified and 

reconstructed fossil fuel-fired EGUs will result in minimal 

compliance costs, because, as previously stated, the EPA expects 

few EGUs to trigger the NSPS modification or reconstruction 

provisions in the period of analysis (through 2022). In Chapter 

6 of the RIA, we discuss factors that limit our ability to 

quantify the costs and benefits of the standards for modified 

and reconstructed sources.
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B. Paperwork Reduction Act (PRA)

 The information collection activities in this final action 

have been submitted for approval to OMB under the PRA. The 

Information Collection Request (ICR) document that the EPA 

prepared has been assigned EPA ICR number 2465.03. Separate ICR 

documents were prepared and submitted to OMB for the proposed 

standards for newly constructed EGUs (EPA ICR number 2465.02) 

and the proposed standards for modified and reconstructed EGUs 

(EPA ICR number 2506.01). Because the CO2 standards for newly 

constructed, modified, and reconstructed EGUs will be included 

in the same new subpart (40 CFR part 60, subpart TTTT) and are 

being finalized in the same action, the ICR document for this 

action includes estimates of the information collection burden 

on owners and operators of newly constructed, modified, and 

reconstructed EGUs. Estimated cost burden is based on 2013 

Bureau of Labor Statistics (BLS) labor cost data. Thus, all 

burden estimates are in 2013 dollars. Burden is defined at 5 CFR 

1320.3(b). You can find a copy of the ICR in the dockets for 

this action (Docket ID Numbers EPA-HQ-OAR-2013-0495 and EPA-HQOAR-2013-0603), and it is briefly summarized here. The 

information collection requirements are not enforceable until 

OMB approves them.

The recordkeeping and reporting requirements in this final 

action are specifically authorized by CAA section 114 (42 U.S.C. 
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7414). All information submitted to the EPA pursuant to the 

recordkeeping and reporting requirements for which a claim of 

confidentiality is made is safeguarded according to agency

policies set forth in 40 CFR part 2, subpart B.

An agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR 

part 9. When OMB approves this ICR, the agency will announce 

that approval in the Federal Register and publish a technical 

amendment to 40 CFR part 9 to display the OMB control number for 

the approved information collection activities contained in this 

final action.

1. Newly Constructed EGUs

This final action will impose minimal new information 

collection burden on owners and operators of affected newly 

constructed fossil fuel-fired EGUs (steam generating units and 

stationary combustion turbines) beyond what those sources would 

already be subject to under the authorities of CAA parts 75 and 

98. OMB has previously approved the information collection 

requirements contained in the existing part 75 and 98 

regulations (40 CFR part 75 and 40 CFR part 98) under the 

provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et

seq. and has assigned OMB control numbers 2060-0626 and 2060-
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0629, respectively. Apart from certain reporting costs to comply 

with the emission standards under the rule, there are no new 

information collection costs, as the information required by the 

standards for newly constructed EGUs is already collected and 

reported by other regulatory programs. 

 The EPA believes that electric power companies will choose 

to build new EGUs that comply with the regulatory requirements 

of the rule because of existing and expected market conditions. 

The EPA does not project any newly constructed coal-fired steam 

generating units that commenced construction after proposal 

(January 8, 2014) to commence operation over the 3-year period 

covered by this ICR. We estimate that 12 affected newly 

constructed NGCC units and 25 affected newly constructed natural 

gas-fired simple cycle combustion turbines will commence 

operation during that time period. As a result of this final 

action, owners or operators of those newly constructed units 

will be required to prepare a summary report, which includes 

reporting of emissions and downtime, every 3 months.

2. Modified and Reconstructed EGUs

This final action is not expected to impose an information 

collection burden under the provisions of the PRA on owners and 

operators of affected modified and reconstructed fossil fuelfired EGUs (steam generating units and stationary combustion 

turbines). As previously stated, the EPA expects few EGUs to 
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trigger the NSPS modification or reconstruction provisions in 

the period of analysis. Specifically, the EPA believes it 

unlikely that fossil fuel-fired electric utility steam 

generating units or stationary combustion turbines will take 

actions that would constitute modifications or reconstructions 

as defined under the EPA’s NSPS regulations. Accordingly, the 

standards for modified and reconstructed EGUs are not 

anticipated to impose any information collection burden over the 

3-year period covered by this ICR. We have estimated, however, 

the information collection burden that would be imposed on an 

affected EGU if it was modified or reconstructed.

Although not anticipated, if an EGU were to modify or 

reconstruct, this final action would impose minimal information 

collection burden on those affected EGUs beyond what they would 

already be subject to under the authorities of CAA 40 CFR parts 

75 and 98. As described above, the OMB has previously approved 

the information collection requirements contained in the 

existing part 75 and 98 regulations. Apart from certain 

reporting costs to comply with the emission standards under the 

rule, there would be no new information collection costs, as the 

information required by the final rule is already collected and 

reported by other regulatory programs.

As stated above, although the EPA expects few sources will 

trigger either the NSPS modification or reconstruction 
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provisions, if an EGU were to modify or reconstruct during the 

3-year period covered by this ICR, the owner or operator of the 

EGU will be required to prepare a summary report, which includes 

reporting of emissions and downtime, every 3 months. The annual 

reporting burden for such a unit is estimated to be $1,333 and 

16 labor hours. There are no annualized capital costs or O&M 

costs associated with burden for modified or reconstructed EGUs.

3. Information Collection Burden

The annual information collection burden for newly 

constructed, modified, and reconstructed EGUs consists only of 

reporting burden as explained above. The annual reporting burden 

for this collection (averaged over the first 3 years after the 

effective date of the standards) is estimated to be $60,977 and 

651 labor hours. There are no annualized capital costs or O&M 

costs associated with burden for newly constructed, modified, or 

reconstructed EGUs. Average burden hours per response are 

estimated to be 7 hours. The total number of respondents over 

the 3-year ICR period is estimated to be 62.

C. Regulatory Flexibility Act (RFA)

I certify that this final action will not have a 

significant economic impact on a substantial number of small 

entities under the RFA. In making this determination, the impact 

of concern is any significant adverse economic impact on small 

entities. An agency may certify that a rule will not have a 
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significant economic impact on a substantial number of small 

entities if the rule relieves regulatory burden, has no net 

burden or otherwise has a positive economic effect on the small 

entities subject to the rule.

1. Newly Constructed EGUs

The EPA believes that electric power companies will choose 

to build new fossil fuel-fired electric utility steam generating 

units or natural gas-fired stationary combustion turbines that 

comply with the regulatory requirements of the final rule 

because of existing and expected market conditions. RIA Chapter 

4. The EPA does not project any new coal-fired steam generating 

units without CCS to be built. We expect that any newly 

constructed natural gas-fired stationary combustion turbines 

will meet the standards. We do not include an analysis of the 

illustrative impacts on small entities that may result from 

implementation of the final rule because we anticipate 

negligible compliance costs over a range of likely sensitivity 

conditions as a result of the standards for newly constructed 

EGUs. Thus the cost-to-sales ratios for any affected small 

entity would be zero costs as compared to annual sales revenue 

for the entity. Accordingly, there are no anticipated economic 

impacts as a result of the standards for newly constructed EGUs.

(See the “Regulatory Impact Analysis for the Standards of 

Performance for Greenhouse Gas Emissions for New, Modified, and 
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Reconstructed Stationary Sources: Electric Utility Generating 

Units” (EPA-452/R-15-005, August 2015) for further discussion of 

sensitivities.) We have therefore concluded that this final 

action will have no net regulatory burden for all directly 

regulated small entities.

2. Modified and Reconstructed EGUs

The EPA expects few fossil fuel-fired electric utility

steam generating units to trigger the NSPS modification 

provisions in the period of analysis. An NSPS modification is 

defined as a physical or operational change that increases the 

source’s maximum achievable hourly rate of emissions. The EPA 

does not believe that there are likely to be EGUs that will take 

actions that would constitute modifications as defined under the 

EPA’s NSPS regulations.

In addition, the EPA expects few reconstructed fossil fuelfired electric utility steam generating units or natural gasfired stationary combustion turbines in the period of analysis. 

Reconstruction occurs when a single project replaces components 

or equipment in an existing facility and exceeds 50 percent of 

the fixed capital cost that would be required to construct a 

comparable entirely new facility.

In Chapter 6 of the RIA, we discuss factors that limit our 

ability to quantify the costs and benefits of the standards for 

modified and reconstructed sources. However, we do not 
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anticipate that the rule would impose significant costs on those 

sources, including any that are owned by small entities. (See 

the “Regulatory Impact Analysis for the Standards of Performance 

for Greenhouse Gas Emissions for New, Modified, and 

Reconstructed Stationary Sources: Electric Utility Generating 

Units” (EPA-452/R-15-005, August 2015).

D. Unfunded Mandates Reform Act (UMRA)

This final action does not contain an unfunded mandate of 

$100 million or more as described in UMRA, 2 U.S.C. 1531–1538, 

and does not significantly or uniquely affect small governments.

The EPA believes the final rule will have negligible 

compliance costs on owners and operators of newly constructed 

EGUs over a range of likely sensitivity conditions because 

electric power companies will choose to build new fossil fuelfired electric utility steam generating units or natural gasfired stationary combustion turbines that comply with the 

regulatory requirements of the rule because of existing and 

expected market conditions. The EPA does not project any new 

coal-fired steam generating units without CCS to be built and 

expects that any newly constructed natural gas-fired stationary 

combustion turbines will meet the standards. (See the 

“Regulatory Impact Analysis for the Standards of Performance for 

Greenhouse Gas Emissions for New, Modified, and Reconstructed 

Stationary Sources: Electric Utility Generating Units” (EPA-
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452/R-15-005, August 2015) for further discussion of 

sensitivities.)

As previously stated, the EPA expects few fossil fuel-fired 

electric utility steam generating units or natural gas-fired 

stationary combustion turbines to trigger the NSPS modification 

or reconstruction provisions in the period of analysis. In 

Chapter 6 of the RIA, we discuss factors that limit our ability 

to quantify the costs and benefits of the standards for modified 

and reconstructed sources. However, we do not anticipate that 

the rule would impose significant costs on those sources. (See 

the “Regulatory Impact Analysis for the Standards of Performance 

for Greenhouse Gas Emissions for New, Modified, and 

Reconstructed Stationary Sources: Electric Utility Generating 

Units” (EPA-452/R-15-005, August 2015).)

We have therefore concluded that the standards for newly 

constructed, modified, and reconstructed EGUs do not impose 

enforceable duties on any state, local or tribal governments, or 

the private sector, that may result in expenditures by state, 

local and tribal governments, in the aggregate, or to the 

private sector, of $100 million or more in any one year. We have 

also concluded that this action does not have regulatory 

requirements that might significantly or uniquely affect small 

governments. The threshold amount established for determining 

whether regulatory requirements could significantly affect small 
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governments is $100 million annually and, as stated above, we 

have concluded that the final action will not result in 

expenditures of $100 million or more in any one year. 

Specifically, the EPA does not project any new coal-fired steam 

generating units without CCS to be built and expects that any 

newly constructed natural gas-fired stationary combustion 

turbines will meet the standards. Further, the EPA expects few 

fossil fuel-fired electric utility steam generating units or 

natural gas-fired stationary combustion turbines to trigger the 

NSPS modification or reconstruction provisions in the period of 

analysis.

E. Executive Order 13132: Federalism

This final action does not have federalism implications. It 

will not have substantial direct effects on the states, on the 

relationship between the national government and the states, or 

on the distribution of power and responsibilities among the 

various levels of government. The EPA believes that electric 

power companies will choose to build new fossil fuel-fired 

electric utility steam generating units or natural gas-fired 

stationary combustion turbines that comply with the regulatory 

requirements of the final rule because of existing and expected 

market conditions. In addition, as previously stated, the EPA 

expects few fossil fuel-fired electric utility steam generating 

units or natural gas-fired stationary combustion turbines to 
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trigger the NSPS modification or reconstruction provisions in 

the period of analysis. We, therefore, anticipate that the final 

rule will impose minimal compliance costs.

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

This final action does not have tribal implications as 

specified in Executive Order 13175. The final rule will impose 

requirements on owners and operators of newly constructed, 

modified, and reconstructed EGUs. The EPA is aware of three 

facilities with coal-fired steam generating units, as well as 

one facility with natural gas-fired stationary combustion 

turbines, located in Indian Country, but is not aware of any 

EGUs owned or operated by tribal entities. We note that because 

the rule addresses CO2 emissions from newly constructed, 

modified, and reconstructed EGUs, it will affect existing EGUs 

such as those located at the four facilities in Indian Country 

only if those EGUs were to take actions constituting 

modifications or reconstructions as defined under the EPA’s NSPS 

regulations. As previously stated, the EPA expects few EGUs to 

trigger the NSPS modification or reconstruction provisions in 

the period of analysis. Thus, the rule will neither impose 

substantial direct compliance costs on tribal governments nor 

preempt Tribal law. Accordingly, Executive Order 13175 does not 

apply to this action.
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Nevertheless, because the EPA is aware of Tribal interest 

in carbon pollution standards for the power sector and, 

consistent with the EPA Policy on Consultation and Coordination 

with Indian Tribes, the EPA offered consultation with tribal 

officials during development of this rule. Prior to the April 

13, 2012 proposal (77 FR 22392), the EPA sent consultation 

letters to the leaders of all federally recognized tribes. 

Although only newly constructed, modified, and reconstructed 

EGUs will be affected by this action, the EPA’s consultation 

regarded planned actions for new and existing sources. The 

letters provided information regarding the EPA’s development of 

NSPS and emission guidelines for EGUs and offered consultation. 

A consultation/outreach meeting was held on May 23, 2011, with 

the Forest County Potawatomi Community, the Fond du Lac Band of 

Lake Superior Chippewa Reservation, and the Leech Lake Band of 

Ojibwe. A description of that consultation is included in the 

preamble to the proposed standards for new EGUs (79 FR 1501, 

January 8, 2014).

The EPA also offered consultation to the leaders of all 

federally recognized tribes after the proposed action for newly 

constructed EGUs was signed on September, 20, 2013. On November 

1, 2013, the EPA sent letters to tribal leaders that provided 

information regarding the EPA’s development of carbon pollution 

standards for new, modified, reconstructed and existing EGUs and 
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offered consultation. No tribes requested consultation regarding 

the standards for newly constructed EGUs.

In addition to offering consultation, the EPA also 

conducted outreach to tribes during development of this rule. 

The EPA held a series of listening sessions prior to proposal of 

GHG standards for newly constructed EGUs. Tribes participated in 

a session on February 17, 2011, with the state agencies, as well 

as in a separate session with tribes on April 20, 2011. The EPA 

also held a series of listening sessions prior to proposal of 

GHG standards for modified and reconstructed EGUs and GHG 

emission guidelines for existing EGUs. Tribes participated in a 

session on September 9, 2013, together with the state agencies, 

as well as in a separate tribe-only session on September 26, 

2013. In addition, an outreach meeting was held on September 9, 

2013, with tribal representatives from some of the federally 

recognized tribes. The EPA also met with tribal environmental 

staff with the National Tribal Air Association, by 

teleconference, on July 25, 2013, and December 19, 2013. 

Additional detail regarding this stakeholder outreach is 

included in the preamble to the proposed emission guidelines for 

existing EGUs (79 FR 34830, June 18, 2014).
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G. Executive Order 13045: Protection of Children from

Environmental Health Risks and Safety Risks

This action is not subject to Executive Order 13045 because 

it is not economically significant as defined in Executive Order 

12866. While the action is not subject to Executive Order 13045, 

the EPA believes that the environmental health or safety risk 

addressed by this action has a disproportionate effect on 

children. Accordingly, the agency has evaluated the 

environmental health and welfare effects of climate change on 

children. 

CO2 is a potent GHG that contributes to climate change and 

is emitted in significant quantities by fossil fuel-fired power 

plants. As stated above, the EPA believes the final rule will 

have negligible effects on owners and operators of newly 

constructed EGUs over a range of likely sensitivity conditions 

because electric power companies will choose to build new fossil 

fuel-fired electric utility steam generating units or natural 

gas-fired stationary combustion turbines that comply with the 

regulatory requirements of the rule because of existing and 

expected market conditions. However, the RIA also analyzes 

project-level costs of a unit with and without CCS, to quantify 

the potential cost for a fossil fuel-fired unit with CCS. RIA 

chapter 5. Under these scenarios, the rule would result in 

substantial reductions of both CO2, and also fine particulate 
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matter (sulfate PM 2.5) such that net quantifiable benefits 

exceed regulatory costs under a range of assumptions. Under 

these same scenarios, this rule would have a positive effect for 

children’s health.

The assessment literature cited in the EPA’s 2009 

Endangerment Finding concluded that certain populations and 

lifestages, including children, the elderly, and the poor, are 

most vulnerable to climate-related health effects. The 

assessment literature since 2009 strengthens these conclusions 

by providing more detailed findings regarding these groups’ 

vulnerabilities and the projected impacts they may experience.

These assessments describe how children’s unique 

physiological and developmental factors contribute to making 

them particularly vulnerable to climate change. Impacts to 

children are expected from heat waves, air pollution, infectious 

and waterborne illnesses, and mental health effects resulting 

from extreme weather events. In addition, children are among 

those especially susceptible to most allergic diseases, as well 

as health effects associated with heat waves, storms, and 

floods. Additional health concerns may arise in low income 

households, especially those with children, if climate change 

reduces food availability and increases prices, leading to food 

insecurity within households.

More detailed information on the impacts of climate change 
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Page 688 of 764

to human health and welfare is provided in Section II.A of this 

preamble.

H. Executive Order 13211: Actions Concerning Regulations that

Significantly Affect Energy Supply, Distribution, or Use

This final action is not a “significant energy action” 

because it is not likely to have a significant adverse effect on 

the supply, distribution, or use of energy. See Section V.O.3 

above. The EPA believes that electric power companies will 

choose to build new fossil fuel-fired electric utility steam 

generating units or natural gas-fired stationary combustion 

turbines that comply with the regulatory requirements of the 

final rule because of existing and expected market conditions. 

In addition, as previously stated, the EPA expects few fossil 

fuel-fired electric utility steam generating units or natural 

gas-fired stationary combustion turbines to trigger the NSPS 

modification or reconstruction provisions in the period of 

analysis. Thus, this action is not anticipated to have notable 

impacts on emissions, costs or energy supply decisions for the 

affected electric utility industry.

I. National Technology Transfer and Advancement Act (NTTAA) and 

1 CFR part 51

This final action involves technical standards. The EPA has 

decided to use 10 voluntary consensus standards (VCS) in the 

final rule.
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One VCS, American National Standards Institute (ANSI) 

Standard C12.20, “American National Standard for Electricity 

Meters - 0.2 and 0.5 Accuracy Classes,” is cited in the final 

rule to assure consistent monitoring of electric output. This 

standard is available at http://www.ansi.org or by mail at 

American National Standards Institute (ANSI), 25 W. 43rd Street, 

4th Floor, New York, NY, 10036.

Six VCS, American Society for Testing and Materials (ASTM) 

Methods D388-99, “Standard Classification of Coals by Rank”;

D396-98, “Standard Specification for Fuel Oils”; D975-08a,

“Standard Specification for Diesel Fuel Oils”; D3699-08,

“Standard Specification for Kerosene”; D6751-11b, “Standard 

Specification for Biodiesel Fuel Blend Stock (B100) for Middle 

Distillate Fuels”; and D7467-10, “Standard Specification for 

Diesel Fuel Oil, Biodiesel Blend (B6 to B20)” are cited in the 

final rule to identify the different fuel types. These standards 

are available at http://www.astm.org or by mail at ASTM 

International, 100 Barr Harbor Drive, P.O. Box CB700, West 

Conshohocken, PA 19428-2959.

Two VCS, American Society of Mechanical Engineers (ASME) 

Performance Test Codes PTC 22-2014, “Performance Test Codes on 

Gas Turbines” and PTC 46-1996, “Performance Test Codes on 

Overall Plant Performance” are cited in the final rule for their 

guidance on measuring the performance of stationary combustion 
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turbines. These standards are available at http://www.asme.org 

or by mail at American Society of Mechanical Engineers (ASME), 

Two Park Avenue, New York, NY 10016-5990.

One VCS, International Organization for Standardization 

method ISO 2314:2009, “Gas Turbines - Acceptance Tests” is cited 

in the final rule for its guidance on determining performance 

characteristics of stationary combusiton turbines. This standard 

is available at http://www.iso.org/iso/home.htm or by mail at 

International Organization for Standardization (ISO), 1, ch. de 

la Voie-Creuse, Case postale 56, CH-1211 Geneva 20, Switzerland.

Since no EPA Methods were used, there was no need for a 

NTTAA search. The rule also requires use of appendices A, B, D, 

F and G to 40 CFR part 75 and the procedures under 40 CFR 98.33; 

these appendices contain standards that have already been 

reviewed under the NTTAA.

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

Executive Order 12898 (59 FR 7629; February 16, 1994) 

establishes federal executive policy on environmental justice. 

Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental 

justice part of their mission by identifying and addressing, as 

appropriate, disproportionately high and adverse human health or 
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environmental effects of their programs, policies, and 

activities on minority populations and low-income populations in 

the U.S. The EPA defines environmental justice as the fair 

treatment and meaningful involvement of all people regardless of 

race, color, national origin, or income with respect to the 

development, implementation, and enforcement of environmental 

laws, regulations, and policies. The EPA has this goal for all 

communities and persons across this Nation. It will be achieved 

when everyone enjoys the same degree of protection from 

environmental and health hazards and equal access to the 

decision-making process to have a healthy environment in which 

to live, learn, and work.

Leading up to this rulemaking the EPA summarized the public 

health and welfare effects of GHG emissions in its 2009 

Endangerment Finding. As part of the Endangerment Finding, the 

Administrator considered climate change risks to minority or 

low-income populations, finding that certain parts of the 

population may be especially vulnerable based on their 

circumstances. Populations that were found to be particularly 

vulnerable to climate change risks include the poor, the 

elderly, the very young, those already in poor health, the 

disabled, those living alone, and/or indigenous populations 

dependent on one or a few resources. See Sections XIV.F and G, 

above, where the EPA discusses Consultation and Coordination 
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with Tribal Governments and Protection of Children. The 

Administrator placed weight on the fact that certain groups, 

including children, the elderly, and the poor, are most 

vulnerable to climate-related health effects.

The record for the 2009 Endangerment Finding summarizes the 

strong scientific evidence in the major assessment reports by 

the U.S. Global Change Research Program (USGCRP), the 

Intergovernmental Panel on Climate Change (IPCC), and the 

National Research Council (NRC) of the National Academies that 

the potential impacts of climate change raise environmental 

justice issues. These reports concluded that poor communities 

can be especially vulnerable to climate change impacts because 

they tend to have more limited adaptive capacities and are more 

dependent on climate-sensitive resources such as local water and 

food supplies. In addition, Native American tribal communities 

possess unique vulnerabilities to climate change, particularly 

those impacted by degradation of natural and cultural resources 

within established reservation boundaries and threats to 

traditional subsistence lifestyles. Tribal communities whose 

health, economic well-being, and cultural traditions depend upon 

the natural environment will likely be affected by the 

degradation of ecosystem goods and services associated with 

climate change. The 2009 Endangerment Finding record also 

specifically noted that Southwest native cultures are especially 
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vulnerable to water quality and availability impacts. Native 

Alaskan communities are already experiencing disruptive impacts, 

including coastal erosion and shifts in the range or abundance 

of wild species crucial to their livelihoods and well-being. 

The most recent assessments continue to strengthen 

scientific understanding of climate change risks to minority and 

low-income populations in the United States.613 The new 

assessment literature provides more detailed findings regarding 

these populations’ vulnerabilities and projected impacts they 

may experience. In addition, the most recent assessment reports

 

613 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, 

Eds., 2014: Climate Change Impacts in the United States: The 

Third National Climate Assessment. U.S. Global Change Research 

Program, 841 pp.

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 

Vulnerability. Part A: Global and Sectoral Aspects. Contribution 

of Working Group II to the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change [Field, C.B., V.R. 

Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. 

Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. 

Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, 1132 pp.

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 

Vulnerability. Part B: Regional Aspects. Contribution of Working 

Group II to the Fifth Assessment Report of the Intergovernmental 

Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, 

M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. 

Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 

Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 

Cambridge University Press, 688 pp.
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provides new information on how some communities of color may be 

uniquely vulnerable to climate change health impacts in the 

United States. These reports find that certain climate change 

related impacts—including heat waves, degraded air quality, and 

extreme weather events—have disproportionate effects on lowincome and some communities of color, raising environmental 

justice concerns. Existing health disparities and other 

inequities in these communities increase their vulnerability to 

the health effects of climate change. In addition, assessment 

reports also find that climate change poses particular threats 

to health, wellbeing, and ways of life of indigenous peoples in 

the United States.

As the scientific literature presented above and in the 

Endangerment Finding illustrates, low income communities and 

some communities of color are especially vulnerable to the 

health and other adverse impacts of climate change. 

The EPA believes the human health or environmental risk 

addressed by this final action will not have potential 

disproportionately high and adverse human health or 

environmental effects on minority, low-income or indigenous 

populations. The final rule limits GHG emissions from newly 

constructed, modified, and reconstructed fossil fuel-fired 

electric utility steam generating units and newly constructed 
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and modified stationary combustion turbines by establishing 

national emission standards for CO2.

The EPA has determined that the final rule will not result 

in disproportionately high and adverse human health or 

environmental effects on minority, low-income or indigenous 

populations because the rule is not anticipated to notably 

affect the level of protection provided to human health or the 

environment. The EPA believes that electric power companies will 

choose to build new fossil fuel-fired electric utility steam 

generating units and natural gas-fired stationary combustion 

turbines that comply with the regulatory requirements of the 

final rule because of existing and expected market conditions. 

The EPA does not project any new coal-fired steam generating 

units without CCS to be built and expects that any newly built 

natural gas-fired stationary combustion turbines will meet the 

standards. In addition, as previously stated, the EPA expects 

few fossil fuel-fired electric utility steam generating units or 

natural gas-fired stationary combustion turbines to trigger the 

NSPS modification or reconstruction provisions in the period of 

analysis. This final rule will ensure that, to whatever extent 

there are newly constructed, modified, and reconstructed EGUs, 

they will use the best performing technologies to limit 

emissions of CO2.
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K. Congressional Review Act (CRA)

This final action is subject to the CRA, and the EPA will 

submit a rule report to each House of the Congress and to the 

Comptroller General of the United States. This action is not a 

“major rule” as defined by 5 U.S.C. 804(2).

XV. Withdrawal of Proposed Standards for Certain Modified 

Sources

In this action, as discussed above in Sections IV and VI, 

the EPA is issuing final standards of performance for affected 

fossil fuel-fired steam generating EGUs that implement 

modifications resulting in an increase of CO2 emissions (in 

lb/hr) of more than 10 percent. In addition, the EPA is 

withdrawing the proposed standards of performance for emissions 

of carbon dioxide (CO2) from modified fossil fuel-fired EGUs not 

covered by those final standards. Specifically, the EPA is 

withdrawing the proposed standards for fossil fuel-fired steam 

generating EGUs that implement modifications resulting in an 

increase of CO2 emissions (in lb/hr) of less than or equal to 10 

percent. A detailed rationale for the withdrawal of these 

proposed standards is provided in Section VI above. 

The EPA is also, in this action, withdrawing proposed 

standards for modified stationary combustion turbines. A 

detailed rationale for the withdrawal of these proposed 

standards is provided in Section IX above.
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The proposed standards for modified fossil fuel-fired EGUs 

that the EPA is withdrawing in this action were published in the 

Federal Register on June 18, 2014 (79 FR 34960).

XVI. Statutory Authority

The statutory authority for this action is provided by 

sections 111, 301, 302, and 307(d)(1)(C) of the CAA as amended 

(42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C)). This action is also 

subject to section 307(d) of the CAA (42 U.S.C. 7607(d)).
Page 698 of 764

List of Subjects

40 CFR Part 60

Environmental protection, Administrative practice and 

procedure, Air pollution control, Incorporation by reference, 

Intergovernmental relations, Reporting and recordkeeping 

requirements.

40 CFR Part 70

Environmental protection, Administrative practice and 

procedure, Air pollution control, Intergovernmental relations, 

Reporting and recordkeeping requirements.

40 CFR Part 71

Environmental protection, Administrative practice and 

procedure, Air pollution control, Reporting and recordkeeping 

requirements.

40 CFR Part 98

Environmental protection, Greenhouse gases and monitoring, 

Reporting and recordkeeping requirements.

Dated: __________________. 

________________________

Gina McCarthy,

Administrator
Page 699 of 764

For the reasons stated in the preamble, title 40, chapter I, 

part 60, 70, 71, and 98 of the Code of the Federal Regulations 

is amended as follows:

PART 60-- STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

1. The authority citation for part 60 continues to read as 

follows:

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

2. Section 60.17 is amended by:

a. Redesignating paragraphs (d) through (t) as paragraphs 

(e) through (u) and adding new paragraphs (d) and (d)(1);

b. In redesignated paragraph (g), further redesignating 

paragraph (g)(15) as paragraph (g)(17) and adding new paragraphs 

(g)(15) and (g)(16);

c. In redesignated paragraph (h), revising paragraphs 

(h)(37), (h)(42), (h)(46), (h)(138), (h)(187), and (h)(190); and

c. In redesignated paragraph (m), further redesignating 

paragraph (m)(1) as paragraph (m)(2) and adding new paragraph 

(m)(1).

The additions read as follows:

§60.17 Incorporations by reference.

* * * * *

(d) The following material is available for purchase from 

the American National Standards Institute (ANSI), 25 W. 43rd 
Page 700 of 764

Street, 4th Floor, New York, NY, 10036, Telephone (212) 642-

4980, and is also available at the following Web site: 

http://www.ansi.org

(1) ANSI No. C12.20-2010 American National Standard for 

Electricity Meters--0.2 and 0.5 Accuracy Classes (Approved 

August 31, 2010), IBR approved for §60.5535(d).

* * * * *

(g) * * *

(15) ASME PTC 22-2014, Gas Turbines: Performance Test 

Codes, (Issued December 31, 2014), IBR approved for §60.5535(h).

(16) ASME PTC 46-1996, Performance Test Code on Overall 

Plant Performance, (Issued November 28, 1996), IBR approved for 

§60.5535(h).

* * * * *

(h) * * *

(37) ASTM D388-99 (Reapproved 2004)ε,1 Standard 

Specification for Classification of Coals by Rank, IBR approved 

for §§60.41, 60.45(f), 60.41Da, 60.41b, 60.41c, 60.251, and 

60.5580. 

* * * * *

(42) ASTM D396-98, Standard Specification for Fuel Oils, 

IBR approved for §§60.41b, 60.41c, 60.111(b), 60.111a(b), and 

60.5580.

* * * * *
Page 701 of 764

(46) ASTM D975-08a, Standard Specification for Diesel Fuel 

Oils, IBR approved for §§60.41b 60.41c, and 60.5580. 

* * * * *

(138) ASTM D3699-08, Standard Specification for Kerosine, 

including Appendix X1, (Approved September 1, 2008), IBR 

approved for §§60.41b, 60.41c, and 60.5580.

* * * * *

(187) ASTM D6751-11b, Standard Specification for Biodiesel 

Fuel Blend Stock (B100) for Middle Distillate Fuels, including 

Appendices X1 through X3, (Approved July 15, 2011), IBR approved 

for §§60.41b, 60.41c, and 60.5580.

* * * * *

(190) ASTM D7467-10, Standard Specification for Diesel Fuel 

Oil, Biodiesel Blend (B6 to B20), including Appendices X1 

through X3, (Approved August 1, 2010), IBR approved for 

§§60.41b, 60.41c, and 60.5580.

* * * * *

(m) * * *

(1) ISO 2314:2009, Gas turbines–Acceptance tests, (Issued 

December 15, 2009), IBR approved for §60.5535(h).

* * * * *

3. Part 60 is amended by adding subpart TTTT to read as 

follows:

Subpart TTTT Standards of Performance for Greenhouse Gas 
Page 702 of 764

Emissions for Electric 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 Which pollutants 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? 

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 EGU?

§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?
Page 703 of 764

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 modification or reconstruction after June 18, 2014. An 

affected steam generating unit, IGCC, or stationary combustion 

turbine shall, for the purposes of this subpart, be referred to 

as an affected EGU.

§60.5509 Am I subject to this subpart?

(a) Except as provided for in paragraph (b) of this 

section, the GHG standards included in this subpart apply to any 

steam generating unit, IGCC, or stationary combustion turbine 

that commenced construction after January 8, 2014 or commenced 

reconstruction after June 18, 2014 that meets the relevant 

applicability conditions in paragraphs (a)(1) and (a)(2) of this 

section. The GHG standards included in this subpart also apply 

to any steam generating unit or IGCC that commenced modification 

after June 18, 2014 that meets the relevant applicability 

conditions in paragraphs (a)(1) and (a)(2) of this section.

(1) Has a base load rating greater than 260 GJ/h (250 

MMBtu/h) of fossil fuel (either alone or in combination with any 

other fuel), and

(2) Serves a generator capable of selling greater than 25 

MW of electricity to a utility power distribution system. 
Page 704 of 764

(b) You are not subject to the requirements of this subpart 

if your affected EGU meets any of the conditions specified in 

paragraphs (b)(1) through (b)(8) of this section.

(1) Your EGU is a steam generating unit or IGCC that is 

currently and always has been subject to a federally enforceable 

permit condition limiting annual net-electric sales to no more 

than one-third of its potential electric output or 219,000 MWh, 

whichever is greater.

(2) Your EGU is capable of combusting 50 percent or more 

non-fossil fuel and is also subject to a federally enforceable 

permit condition limiting the annual capacity factor for all 

fossil fuels combined of 10 percent (0.10) or less. 

(3) Your EGU is a combined heat and power unit that is 

subject to a federally enforceable permit condition limiting 

annual net-electric sales to no more than the product of the 

unit's net design efficiency and the unit's potential electric 

output or 219,000 MWh, whichever is greater.

(4) Your EGU serves a generator along with other steam 

generating unit(s), IGCC, or stationary combustion turbine(s) 

where the effective generation capacity (determined based on a 

prorated output of the base load rating of each steam generating 

unit, IGCC, or stationary combustion turbine) is 25 MW or less.

(5) Your EGU is a municipal waste combustor that is subject 

to subpart Eb of this part.
Page 705 of 764

(6) Your EGU is a commercial or industrial solid waste 

incineration unit that is subject to subpart CCCC of this part.

(7) Your EGU is a steam generating unit or IGCC that 

undergoes a modification resulting in an hourly increase in CO2

emissions (mass per hour) of 10 percent or less (2 significant 

figures). Modified units that are not subject to the 

requirements of this subpart pursuant to this subsection 

continue to be existing units under section 111 with respect to 

CO2 emissions standards.

(8) Your EGU is a stationary combustion turbine that is not 

capable of combusting natural gas (e.g., not connected to a 

natural gas pipeline).

(9) 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.

(10) 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.

Emission Standards
Page 706 of 764

§60.5515 Which pollutants are regulated by this subpart?

(a) The pollutants regulated by this subpart are greenhouse 

gases. The greenhouse gas standard in this subpart is in the 

form of a limitation on emission of carbon dioxide.

(b) PSD and Title V Thresholds for Greenhouse Gases.

(1) For the 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 §51.166(b)(48) and in any SIP approved by 

the EPA that is interpreted to incorporate, or specifically 

incorporates, §51.166(b)(48) of this chapter.

(2) For the 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 §52.21(b)(49) of this chapter.

(3) For the purposes of 40 CFR §70.2 of this chapter, 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 
Page 707 of 764

§70.2 of this chapter.

(4) For the 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 of this chapter.

§60.5520 What CO2 emission standard must I meet?

(a) For each affected EGU subject to this subpart, you must 

not discharge from the affected EGU any gases that contain CO2 in 

excess of the applicable CO2 emission standard specified in 

Table 1 or Table 2 of this subpart, consistent with paragraphs 

(b), (c), and (d) of this section, as applicable. 

(b) Except as specified in paragraphs (c) and (d) of this

section, you must comply with the applicable gross energy output 

standard and your operating permit must include monitoring, 

recordkeeping, and reporting methodologies based on the 

applicable gross energy output standard. For the remainder of 

this subpart (for sources that do not qualify under paragraphs 

(c) and (d) of this section), where the term “gross or net 

energy output” is used, the term that applies to you is “gross 

energy output”.”

(c) As an alternate to meeting the requirements in 

paragraph (b) of this section, an owner or operator of a 
Page 708 of 764

stationary combustion turbine may petition the Administrator in 

writing to comply with the alternate applicable net energy 

output standard. If the Administrator grants the petition, 

beginning on the date the Administrator grants the petition, the 

affected EGU must comply with the applicable net energy output 

based standard included in this subpart. Your operating permit 

must include monitoring, recordkeeping, and reporting 

methodologies based on the applicable net energy output 

standard. For the remainder of this subpart, where the term 

“gross or net energy output” is used, the term that applies to 

you is “net energy output.” Owners or operators complying with 

the net output based standard must petition the Administrator to 

switch back to complying with the gross energy output based 

standard.

(d) Stationary combustion turbines subject to a heat input 

based standard in Table 2 that are only permitted to burn one or 

more of the fuels listed in paragraph (d)(1) of this section are 

only subject to the monitoring requirements in paragraph (d)(1)

of this section. All other stationary combustion turbines 

subject to a heat input based standard in Table 2 are subject to 

the requirements in paragraph (d)(2) of this section.

(1) Stationary combustion turbines that are only permitted 

to burn fuels with a consistent chemical composition (i.e., 

uniform fuels) that result in a consistent emission rate of 160 
Page 709 of 764

lb CO2/MMBtu or are not subject to any monitoring or reporting 

requirements under this subpart. These fuels include, but are 

not limited to, natural gas, methane, butane, butylene, ethane, 

ethylene, propane, naphtha, propylene, jet fuel kerosene, 

distillate oil No. 1, No. 2, and biodiesel. Stationary 

combustion turbines qualifying under this paragraph are only 

required to maintain purchase records for permitted fuels. 

(2) Stationary combustion turbines permitted to burn fuels 

that do not have a consistent chemical composition or that do 

have an emission rate of 160 lb CO2/MMBtu or less (e.g., nonuniform fuels such as residual oil and non-jet fuel kerosene)

must follow the monitoring, recordkeeping, and reporting 

requirements necessary to complete the heat input based 

calculations under this subpart. 

General Compliance Requirements

§60.5525 What are my general requirements for complying with 

this subpart?

Combustion turbines qualifying under § 60.5520(d)(1) are 

not subject to any requirements in this section other than the 

requirement to maintain fuel purchase records for permitted 

fuel(s). For all other affected sources, compliance with the 

applicable CO2 emission standard of this subpart shall be 

determined on a 12-operating-month rolling average basis. See 

Table 1 or 2 for the applicable CO2 emission standards. 
Page 710 of 764

(a) You must be in compliance with the emission standards 

in this subpart that apply to your affected EGU at all times. 

However, you must determine compliance with the emission 

standards only at the end of the applicable operating month, as 

provided in paragraph (a)(1). 

(1) For each affected EGU 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 EGU at the end of the initial 

and each subsequent 12-operating-month period.

(2) Consistent with §60.5520(d)(2), if your affected 

stationary combustion turbine is subject to an input-based CO2

emissions standard, you must determine the total heat input in 

million Btu’s (MMBtu) from natural gas (HTIPng) and the total 

heat input from all other fuels combined (HTIPo) using one of the 

methods under §60.5535(d)(2). You must then use the following 

equation to determine the applicable emissions standard during 

the compliance period:

 emission	standard	=	

120 x HTIP + (160 x HTIP

)

HTIP + HTIP

Where:

CO2 emission standard = the emission standard during the 

compliance period in units of lb/MMBtu.

HTIPng = the heat input in MMBtu from natural gas.
Page 711 of 764

HTIPo = the heat input in MMBtu from all fuels other than 

natural gas.

120 = allowable emission rate in lbs of CO2/MMBtu for heat 

input derived from natural gas.

160 = allowable emission rate in lbs of CO2/MMBtu for heat 

input derived from all fuels other than natural 

gas.

(b) At all times you must operate and maintain each 

affected EGU, including associated equipment and monitors, 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 EGU.

(c) Within 30 days after the end of the initial compliance 

period (i.e., no more than 30 days after the first 12-operatingmonth compliance period), you must make an initial compliance 

determination for your affected EGU(s) with respect to the 

applicable emissions standard in Table 1 or Table 2 of this 

subpart, in accordance with the requirements in this subpart. 

The first operating month included in the initial 12-operatingmonth compliance period shall be determined as follows: 
Page 712 of 764

(1) For an affected EGU that commences commercial operation 

(as defined in §72.2 of this chapter) on or after the effective 

date of this rule, the first month of the initial compliance 

period shall be the first operating month (as defined in 

§60.5580) after the calendar month in which emissions reporting 

is required to begin under:

(i) §63.5555(c)(3)(i), for units subject to the Acid Rain 

Program; or 

(ii) §63.5555(c)(3)(ii)(A), for units that are not in the 

Acid Rain Program.

(2) For an affected EGU that has commenced commercial 

operation (as defined in §72.2 of this chapter) prior to the 

effective date of this rule:

(i) If the date on which emissions reporting is required to 

begin under §75.64(a) of this chapter has passed prior to the 

effective date of this rule, emissions reporting shall begin 

according to §63.5555(c)(3)(i) (for Acid Rain program units), or 

according to §63.5555(c)(3)(ii)(B) (for units that are not 

subject to the Acid Rain Program). The first month of the 

initial compliance period shall be the first operating month (as 

defined in §60.5580) after the calendar month in which the rule 

becomes effective; or

(ii) If the date on which emissions reporting is required 

to begin under §75.64(a) of this chapter occurs on or after the 
Page 713 of 764

effective date of this rule, then the first month of the initial 

compliance period shall be the first operating month (as defined 

in §60.5580) after the calendar month in which emissions 

reporting is required to begin under §63.5555(c)(3)(ii)(A).

(3) For a modified or reconstructed EGU that becomes 

subject to this subpart, the first month of the initial 

compliance period shall be the first operating month (as defined 

in §60.5580) after the calendar month in which emissions 

reporting is required to begin under §63.5555(c)(3)(iii).

Monitoring and Compliance Determination Procedures

§60.5535 How do I monitor and collect data to demonstrate 

compliance?

(a) Combustion turbines qualifying under §60.5520(d)(1) are 

not subject to any requirements in this section other than the 

requirement to maintain fuel purchase records for permitted 

fuel(s). If your combustion turbine uses non-uniform fuels as 

specified under §60.5520(d)(2), you must monitor heat input in 

accordance with paragraph (c)(1) of this section, and you must 

monitor CO2 emissions in accordance with either paragraph (b), 

(c)(2), or (c)(5) of this section. For all other affected 

sources, you must prepare a monitoring plan to quantify the 

hourly CO2 mass emission rate (tons/h), in accordance with the 

applicable provisions in §75.53(g) and (h) of this chapter. The 

electronic portion of the monitoring plan must be submitted 
Page 714 of 764

using the ECMPS Client Tool and must be in place prior to 

reporting emissions data and/or the results of monitoring system 

certification tests under this subpart. The monitoring plan must 

be updated as necessary. Monitoring plan submittals must be made 

by the Designated Representative (DR), the Alternate DR, or a 

delegated agent of the DR (see §60.5555(c)).

(b) You must determine the hourly CO2 mass emissions in 

kilograms (kg) from your affected EGU(s) according to paragraphs 

(b)(1) through (5) of this section, or, if applicable, as 

provided in paragraph (c) of this section.

(1) For an affected coal-fired EGU or for an IGCC unit you 

must, and for all other affected EGUs you may, install, certify, 

operate, maintain, and calibrate a CO2 continuous emission 

monitoring system (CEMS) to directly measure and record hourly 

average CO2 concentrations in the affected EGU exhaust gases 

emitted to the atmosphere, and a flow monitoring system to 

measure hourly average stack gas flow rates, according to 

§75.10(a)(3)(i) of this chapter. As an alternative to direct 

measurement of CO2 concentration, provided that your EGU does not 

use carbon separation (e.g., carbon capture and storage), you 

may use data from a certified oxygen (O2) monitor to calculate 

hourly average CO2 concentrations, in accordance with 

§75.10(a)(3)(iii) of this chapter. If you measure CO2

concentration on a dry basis, you must also install, certify, 
Page 715 of 764

operate, maintain, and calibrate a continuous moisture 

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

Alternatively, you may either use an appropriate fuel-specific 

default moisture value from §75.11(b) or submit a petition to 

the Administrator under §75.66 of this chapter for a sitespecific default moisture value.

(2) For each continuous 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 A and B to part 75 of this chapter.

(3) You must use only unadjusted exhaust gas volumetric 

flow rates to determine the hourly CO2 mass emissions rate from 

the affected EGU; 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.

(4) You must select an appropriate reference method to 

setup (characterize) the flow monitor and to perform the ongoing RATAs, in accordance with part 75 of this chapter. If you 

use a Type-S pitot tube or a pitot tube assembly for the flow 

RATAs, you must calibrate the pitot tube or pitot tube assembly; 

you may not use the 0.84 default Type-S pitot tube coefficient 

specified in Method 2. 

(5) Calculate the hourly CO2 mass emissions (kg) as 

described in paragraphs (a)(6)(i) through (iv) of this section. 
Page 716 of 764

Perform this calculation only for “valid operating hours”, as 

defined in §60.5540(a)(1).

(i) Begin with the hourly CO2 mass emission rate (tons/h), 

obtained either from Equation F-11 in Appendix F to part 75 of 

this chapter (if CO2 concentration is measured on a wet basis), 

or by following the procedure in section 4.2 of Appendix F to 

part 75 of this chapter (if CO2 concentration is measured on a 

dry basis).

(ii) Next, multiply each hourly CO2 mass emission rate by 

the EGU or stack operating time in hours (as defined in §72.2 of 

this chapter), to convert it to tons of CO2. 

(iii) Finally, multiply the result from paragraph 

(b)(5)(ii) of this section by 909.1 to convert it from tons of 

CO2 to kg. Round off to the nearest kg. 

(iv) The hourly CO2 tons/h values and EGU (or stack) 

operating times used to calculate CO2 mass emissions are required 

to be recorded under §75.57(e) of this chapter and must be 

reported electronically under §75.64(a)(6). You must use these 

data to calculate the hourly CO2 mass emissions. 

(c) If your affected EGU 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 according to paragraphs (c)(1) through (4) of 

this section. If you use non-uniform fuels as specified in 
Page 717 of 764

§60.5520(d)(2) you may determine CO2 mass emissions during the 

compliance period according to paragraph (c)(5) of this section.

(1) If you are subject to an output based standard and you 

do not install CEMS in accordance with paragraph (b), you must 

implement the applicable procedures in appendix D to part 75 of 

this chapter to determine hourly EGU 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) For each measured hourly heat input rate, use Equation 

G-4 in Appendix G to part 75 of this chapter to calculate the 

hourly CO2 mass emission rate (tons/h). You may determine sitespecific 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.

(3) For each “valid operating hour” (as defined in 

§60.5540(a)(1), multiply the hourly tons/h CO2 mass emission rate 

from paragraph (c)(2) of this section by the EGU or stack 

operating time in hours (as defined in §72.2 of this chapter), 

to convert it to tons of CO2. Then, multiply the result by 909.1 

to convert from tons of CO2 to kg. Round off to the nearest two 

significant figures.

(4) The hourly CO2 tons/h values and EGU (or stack) 
Page 718 of 764

operating times used to calculate CO2 mass emissions are required 

to be recorded under §75.57(e) of this chapter and must be 

reported electronically under §75.64(a)(6) You must use these 

data to calculate the hourly CO2 mass emissions.

(5) If you operate a combustion turbine firing non-uniform 

fuels, as an alternative to following paragraphs (c)(1)through 

(4) of this section, you may determine CO2 emissions during the 

compliance period using one of the following methods:

(i) Units firing fuel gas may determine the heat input 

during the compliance period following the procedure under 

§60.107a(d) and convert this heat input to CO2 emissions using 

Equation G-4 in Appendix G to Part 75.

(ii) You may use the procedure for determining CO2 emissions 

during the compliance period based on the use of the Tier 3 

methodology under §98.33(a)(3).

(d) Consistent with §60.5520, you must determine the basis 

of the emissions standard that applies to your affected source 

in accordance with either paragraph (d)(1) or (d)(2), as 

applicable:

(1) If you operate a source subject to an emissions 

standard established on an output basis (e.g., lbs of CO2 per 

gross or net MWh of energy output), you must install, calibrate, 

maintain, and operate a sufficient number of watt meters to 

continuously measure and record the hourly gross electric output 
Page 719 of 764

or net electric output, as applicable, from the affected EGU(s). 

These measurements must be performed using 0.2 class electricity 

metering instrumentation and calibration procedures as specified 

under ANSI Standards No. C12.20 (incorporated by reference, see 

60.17). For a combined heat and power (CHP) EGU, as defined in 

§60.5580, you must also install, calibrate, maintain, and 

operate meters to continuously (i.e., hour-by-hour) determine 

and record the total useful thermal output. For process steam 

applications, you will need to install, calibrate, maintain, and 

operate meters to continuously determine and record the hourly 

steam flow rate, temperature, and pressure. Your plan shall 

ensure that you install, calibrate, maintain, and operate meters 

to record each component of the determination, hour-by-hour.

(2) If you operate a source subject to an emissions 

standard established on a heat-input basis (e.g., lb CO2/MMBtu) 

and your affected source uses non-uniform heating value fuels as 

delineated under §60.5520(d), you must determine the total heat 

input for each fuel fired during the compliance period in 

accordance with one of the following procedures:

(i) Appendix D to Part 75;

(ii) The procedures for monitoring heat input under of 

§60.107a(d); 

(iii) If you monitor CO2 emissions in accordance with the 

Tier 3 methodology under §98.33(a)(3), you may convert your CO2
Page 720 of 764

emissions to heat input using the appropriate emission factor in 

Table C-1 of Part 98. If your fuel is not listed in Table C-1, 

you must determine a fuel-specific carbon-based F-factor (Fc) in 

accordance with section 12.3.2 of EPA Method 19 of appendix A-7 

to part 60, and you must convert your CO2 emissions to heat input 

using Equation G-4 in Appendix G to Part 75.

(e) Consistent with §60.5520, if two or more affected EGUs 

serve a common electric generator, you must apportion the 

combined hourly gross or net energy output to the individual 

affected EGUs according to the fraction of the total steam load 

contributed by each EGU. Alternatively, if the EGUs are 

identical, you may apportion the combined hourly gross or net 

electrical load to the individual EGUs according to the fraction 

of the total heat input contributed by each EGU.

(f) In accordance with §60.13(g) and §60.5520, if two or 

more affected EGUs 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 in Table 1 or Table 2 of this subpart, 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 energy output (electric, thermal, and/or 

mechanical, as applicable) must be the sum of the hourly loads 

for the individual affected EGUs and you must express the 
Page 721 of 764

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 EGU sharing the stack is in compliance.

(g) In accordance with §60.13(g) and §60.5520 if the 

exhaust gases from an affected EGU 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 Table 1 or 

2 of this subpart by summing the CO2 mass emissions measured at 

the individual stacks or ducts and dividing by the total gross 

or net energy output for the affected EGU.

§60.5540 How do I demonstrate compliance with my CO2 emissions 

standard?

(a) In accordance with § 60.5520, if you are subject to an 

output based emission standard or you burn non-uniform fuels as 

specified in § 60.5520(d)(2) you must demonstrate compliance 

with the applicable CO2 emission standard in Table 1 or 2 of this 

subpart as required in this section. For the initial and each 
Page 722 of 764

subsequent 12-operating-month rolling average compliance period, 

you must follow the procedures in paragraphs (a)(1) through

(a)(7) of this section to calculate the CO2 mass emissions rate 

for your affected EGU(s) in units of the applicable emissions 

standard (i.e., either kg/MWh or lb/MMBtu). You must use the 

hourly CO2 mass emissions calculated under §60.5535(b) or (c), as 

applicable, and either the generating load data from 

§60.5535(d)(1) for output-based calculations or the heat input 

data from §60.5535(d)(2) for heat-input-based calculations.

Combustion turbines firing non-uniform fuels that contain CO2

prior to combustion (e.g., blast furnace gas or landfill gas) 

may sample the fuel stream to determine the quantity of CO2

present in the fuel prior to combustion and exclude this portion 

of the CO2 mass emissions from compliance determinations.

(1) Each compliance period shall include only “valid 

operating hours” in the compliance period, i.e., operating hours 

for which: 

(i) “Valid data” (as defined in §60.5580) are obtained for 

all of the parameters used to determine the hourly CO2 mass 

emissions (kg) and, if a heat input based standard applies, all 

the parameters used to determine total heat input for the hour 

are also obtained; and
Page 723 of 764

(ii) The corresponding hourly gross or net energy output 

value is also valid data (Note: for hours with no useful output, 

zero is considered to be a valid value). 

(2) You must exclude operating hours in which:

(i) The substitute data provisions of part 75 of this 

chapter are applied for any of the parameters used to determine 

the hourly CO2 mass emissions or, if a heat input based standard 

applies, for any parameters used to determine the hourly heat 

input; or

(ii) An exceedance of the full-scale range of a continuous 

emission monitoring system occurs for any of the parameters used 

to determine the hourly CO2 mass emissions or, if applicable, to 

determine the hourly heat input; or

(iii) The total gross or net energy output (Pgross/net) or, if 

applicable, the total heat input is unavailable.

(3) For each compliance period, at least 95 percent of the 

operating hours in the compliance period must be valid operating 

hours, as defined in paragraph (a)(1) of this section.

(4) You must calculate the total CO2 mass emissions by 

summing the valid hourly CO2 mass emissions values from §60.5535 

for all of the valid operating hours in the compliance period. 

(5) Sources subject to output based standards. For each 

valid operating hour of the compliance period that was used in 

paragraph (a)(4) of this section to calculate the total CO2 mass 
Page 724 of 764

emissions, you must determine Pgross/net (the corresponding hourly 

gross or net energy output in MWh) according to the procedures 

in paragraphs (a)(3)(i) and (ii) of this section, as appropriate 

for the type of affected EGU(s). For an operating hour in which 

a valid CO2 mass emissions value is determined according to 

paragraph (a)(1)(i) of this section, if there is no gross or net 

electrical output, but there is mechanical or useful thermal 

output, you must still determine the gross or net energy output 

for that hour. In addition, for an operating hour in which a 

valid CO2 mass emissions value is determined according to 

paragraph (a)(1)(i) of this section, but there is no (i.e., 

zero) gross electrical, mechanical, or useful thermal output, 

you must use that hour in the compliance determination. For 

hours or partial hours where the gross electric output is equal 

to or less than the auxiliary loads, net electric output shall 

be counted as zero for this calculation.

(i) Calculate Pgross/net for your affected EGU using the 

following equation. All terms in the equation must be expressed 

in units of megawatt-hours (MWh). To convert each hourly gross 

or net energy output (Consistent with §60.5520) value reported 

under part 75 of this chapter to MWh, multiply by the 

corresponding EGU or stack operating time.
Page 725 of 764

/ = 

() + () + () − () − ()

TDF

+ [ () + () + () ]

Where: a

Pgross/net = In accordance with §60.5520, gross or net energy 

output of your affected EGU for each valid 

operating hour (as defined in 60.5540(a)(1)) 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 EGU’s integrated 

equipment that provides electricity or mechanical 

energy to the affected EGU 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, 

IGCC EGUs, or EGUs complying with a net energy 

output based standard.

(Pe)A = Electric energy used for any auxiliary loads in 
Page 726 of 764

MWh. Not applicable for determining Pgross.

(Pt)PS = Useful thermal output of steam (measured relative 

to 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 EGU. This 

is calculated using the equation specified in 

paragraph (a)(5)(ii) of this section in MWh.

(Pt)HR = Non steam useful thermal output (measured 

relative to SATP conditions, as applicable) from 

heat recovery that is used for applications other 

than steam generation or performance enhancement 

of the affected EGU in MWh.

(Pt)IE = Useful thermal output (relative to SATP 

conditions, as applicable) from any integrated 

equipment is used for applications that do not 

generate additional steam, electricity, produce 

mechanical energy output, or enhance the 

performance of the affected EGU in MWh.

TDF = Electric Transmission and Distribution Factor of 

0.95 for a combined heat and power affected EGU 

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 
Page 727 of 764

percent of the total gross or net energy output 

consists of useful thermal output on a 12-

operating-month rolling average basis, or 1.0 for 

all other affected EGUs.

(ii) If applicable to your affected EGU (for example, for 

combined heat and power), you must calculate (Pt)PS using the 

following equation:

() =

 × 



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 SATP conditions or the 

energy in the condensate return line, as 

applicable) in Joules per kilogram (J/kg) (or 

Btu/lb).

CF = Conversion factor of 3.6 x 109 J/MWh or 3.413 x 106 

Btu/MWh.

(6) Calculation of annual basis for standard. Sources 

complying with energy output-based standards must calculate the 

basis (i.e., denominator) of their actual annual emission rate 
Page 728 of 764

in accordance with paragraph (6)(i). Sources complying with heat 

input based standards must calculate the basis of their actual 

annual emission rate in accordance with paragraph (6)(ii).

(i) In accordance with §60.5520 if you are subject to an 

output based standard, you must calculate the total gross or net 

energy output for the affected EGU’s compliance period by 

summing the hourly gross or net energy output values for the 

affected EGU that you determined under paragraph (a)(5) of this 

section for all of the valid operating hours in the applicable 

compliance period.

(ii) If you are subject to a heat input based standard, you 

must calculate the total heat input for each fuel fired during 

the compliance period. The calculation of total heat input for 

each individual fuel must include all valid operating hours and 

must also be consistent with any fuel-specific procedures 

specified within your selected monitoring option under 

§60.5535(d)(2). 

(7) If you are subject to an output based standard, you

must calculate the CO2 mass emissions rate for the affected 

EGU(s) (kg/MWh) by dividing the total CO2 mass emissions value 

calculated according to the procedures in paragraph (a)(4) of 

this section by the total gross or net energy output value 

calculated according to the procedures in paragraph (a)(6)(i) of 

this section. Round off the result to two significant figures if 
Page 729 of 764

the calculated value is less than 1,000; round the result to 

three significant figures if the calculated value is greater 

than 1,000. If you are subject to a heat input based standard, 

you must calculate the CO2 mass emissions rate for the affected 

EGU(s) (lb/MMBtu) by dividing the total CO2 mass emissions value 

calculated according to the procedures in paragraph (a)(4) of 

this section by the total heat input calculated according to the 

procedures in paragraph (a)(6)(ii) of this section. Round off 

the result to two significant figures.

(b) In accordance with §60.5520, to demonstrate compliance 

with the applicable CO2 emission standard, for the initial and 

each subsequent 12-operating-month compliance period, the CO2

mass emissions rate for your affected EGU must be determined 

according to the procedures specified in paragraph (a)(1) 

through (7) of this section and must be less than or equal to 

the applicable CO2 emissions standard in Table 1, Table 2, or the 

emissions standard calculated in accordance with §60.5525(a)(2)

of this subpart. 

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 EGU(s) (see Table 3 of this Subpart).

(b) You must prepare and submit notifications specified in 
Page 730 of 764

§75.61 of this chapter, as applicable to your affected EGUs. 

§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 EGUs that are required by §60.5525 to 

conduct initial and on-going compliance determinations on a 12-

operating-month rolling average basis, you must submit 

electronic quarterly reports as follows. After you have 

accumulated the first 12-operating months for the affected EGU, 

you must submit a report for the calendar quarter that includes 

the twelfth 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 (twelfth) operating month in a 12-operating-month 

compliance period falls within the calendar quarter. You must 

calculate each average CO2 mass emissions rate for the compliance 

period according to the procedures in §60.5540. You must report 

the dates (month and year) of the first and twelfth operating 

months in each compliance period for which you performed a CO2

mass emissions rate calculation. If there are no compliance 
Page 731 of 764

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 

where your EGU violated the applicable CO2 emission standard;

(iii) If one or more compliance periods end in the quarter 

and there are no violations for the affected EGU, you must 

include a statement indicating this in the report;

(iv) The percentage of valid operating hours in each 12-

operating-month compliance period described in paragraph 

(a)(1)(i) of this section (i.e., the total number of valid 

operating hours (as defined in §60.5540(a)(1)) in that period 

divided by the total number of operating hours in that period, 

multiplied by 100 percent);

(v) Consistent with §60.5520, the CO2 emissions standard (as 

identified in Table 1 or 2) with which your affected EGU must 

comply; and

(vi) Consistent with §60.5520, an indication whether or not 

the hourly gross or net energy output (Pgross/net) values used in 

the compliance determinations are based solely upon gross 

electrical load.

(3) In the final quarterly report of each calendar year, 

you must include the following:

(i) Consistent with §60.5520, gross energy output or net 
Page 732 of 764

energy output sold to an electric grid, as applicable to the 

units of your emission standard, over the 4 quarters of the 

calendar year; and

(ii) The potential electric output of the EGU.

(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) (1) For affected EGUs under this subpart that are also 

subject to the Acid Rain Program, you must meet all applicable 

reporting requirements and submit reports as required under 

subpart G of part 75 of this chapter. 

(2) For affected EGUs under this subpart that are not in 

the Acid Rain Program, you must also meet the reporting 

requirements and submit reports as required under subpart G of 

part 75 of this chapter, to the extent that those requirements 

and reports provide applicable data for the compliance 

demonstrations required under this subpart. 

(3) (i) For all newly-constructed affected EGUs under this 

subpart that are also subject to the Acid Rain Program, you must 

begin submitting the quarterly electronic emissions reports 

described in paragraph (c)(1) of this section in accordance with 

§75.64(a), i.e., beginning with data recorded on and after the 
Page 733 of 764

earlier of: 

(A) The date of provisional certification, as defined in 

§75.20(a)(3) of this chapter; or

(B) 180 days after the date on which the EGU commences 

commercial operation (as defined in §72.2 of this chapter). 

(ii) For newly-constructed affected EGUs under this subpart 

that are not subject to the Acid Rain Program, you must begin 

submitting the quarterly electronic reports described in 

paragraph (c)(2) of this section, beginning with data recorded 

on and after:

(A) The date on which reporting is required to begin under 

§75.64(a), if that date occurs on or after the effective date of 

this rule; or

(B) The effective date of this rule, if the date on which 

reporting would ordinarily be required to begin under §75.64(a) 

has passed prior to the effective date of this rule. 

(iii) For reconstructed or modified units, reporting of 

emissions data shall begin at the date on which the EGU becomes 

an affected unit under this subpart, provided that the ECMPS 

Client Tool is able to receive and process net energy output

data on that date. Otherwise, emissions data reporting shall be 

on a gross energy output basis until the date that the Client 

Tool is first able to receive and process net energy output

data.
Page 734 of 764

(4) If any required monitoring system has not been 

provisionally certified by the applicable date on which 

emissions data reporting is required to begin under paragraph 

(c)(3) of this section, the maximum (or in some cases, minimum) 

potential value for the parameter measured by the monitoring 

system shall be reported until the required certification 

testing is successfully completed, in accordance with §75.4(j) 

of this chapter, §75.37(b) of this chapter, or section 2.4 of 

appendix D to part 75 of this chapter (as applicable). 

Operating hours in which CO2 mass emission rates are calculated 

using maximum potential values are not “valid operating hours” 

(as defined in §60.5540(a)(1)), and shall not be used in the 

compliance determinations under §60.5540.

(d) For affected EGUs subject to the Acid Rain Program, the 

reports required under paragraphs (a) and (c)(1) of this section 

shall be submitted by:

(1) The person appointed as the Designated Representative 

(DR) under §72.20 of this chapter; or

(2) The person appointed as the Alternate Designated 

Representative (ADR) under §72.22 of this chapter; or

(3) A person (or persons) authorized by the DR or ADR under 

§72.26 of this chapter to make the required submissions.

(e) For affected EGUs that are not subject to the Acid Rain 

Program, the owner or operator shall appoint a DR and (optional) 
Page 735 of 764

an ADR to submit the reports required under paragraphs (a) and 

(c)(2) of this section. The DR and ADR must register with the 

Clean Air Markets Division (CAMD) Business System. The DR may 

delegate the authority to make the required submissions to one 

or more persons.

(f) If your affected EGU captures CO2 to meet the applicable 

emission limit, you must report in accordance with the 

requirements of 40 CFR Part 98 Subpart PP and either:

(1) Report in accordance with the requirements of 40 CFR 

Part 98 subpart RR, if injection occurs on-site, or

(2) Transfer the captured CO2 to an EGU or facility that 

reports in accordance with the requirements of 40 CFR Part 98 

subpart RR, if injection occurs off-site.

(3) Transfer the captured CO2 to a facility that has received an 

innovative technology waiver from EPA pursuant to paragraph (g) 

of this section.

(g) Any person may request the Administrator to issue a 

waiver of the requirement that captured CO2 from an affected EGU 

be transferred to a facility reporting under 40 CFR Part 98 

subpart RR. To receive a waiver, the applicant must demonstrate 

to the Administrator that its technology will store captured CO2

as effectively as geologic sequestration, and that the proposed 

technology will not cause or contribute to an unreasonable risk 

to public health, welfare, or safety. In making this 
Page 736 of 764

determination, the Administrator shall consider (among other 

factors) operating history of the technology, whether the 

technology will increase emissions or other releases of any 

pollutant other than CO2, and permanence of the CO2 storage. The 

Administrator may test the system itself, or require the 

applicant to perform any tests considered by the Administrator 

to be necessary to show the technology’s effectiveness, safety, 

and ability to store captured CO2 without release. The 

Administrator may grant conditional approval of a technology, 

the approval conditioned on monitoring and reporting of 

operations. The Administrator may also withdraw approval of the 

waiver on evidence of releases of CO2 or other pollutants. The 

Administrator will provide notice to the public of any 

application under this provision, and provide public notice of 

any proposed action on a petition before the Administrator takes 

final action.

§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).

(b) (1) For affected EGUs subject to the Acid Rain Program, 

you must follow the applicable recordkeeping requirements and 

maintain records as required under subpart F of part 75 of this 

chapter.
Page 737 of 764

(2) For affected EGUs that are not subject to the Acid Rain 

Program, you must also follow the recordkeeping requirements and 

maintain records as required under subpart F of part 75 of this 

chapter, to the extent that those records provide applicable 

data for the compliance determinations required under this 

subpart. Regardless of the prior sentence, at a minimum, the 

following records must be kept, as applicable to the types of 

continuous monitoring systems used to demonstrate compliance 

under this subpart:

(i) Monitoring plan records under §75.53(g) and (h) of this 

chapter;

(ii) Operating parameter records under §75.57(b)(1) through 

(b)(4) of this chapter;

(iii) The records under §75.57(c)(2) of this chapter, for 

stack gas volumetric flow rate; 

(iv) The records under §75.57(c)(3) for continuous moisture 

monitoring systems;

(v) The records under §75.57(e)(1), except for paragraph 

(e)(1)(x), for CO2 concentration monitoring systems or O2

monitors used to calculate CO2 concentration;

(vi) The records under §75.58(c)(1), paragraphs (c)(1)(i), 

(c)(1)(ii), and (c)(1)(viii) through (c)(1)(xiv), for oil flow 

meters;

(vii) The records under §75.58(c)(4), paragraphs (c)(4)(i), 
Page 738 of 764

(c)(4)(ii), (c)(4)(iv), (c)(4)(v), and (c)(4)(vii) through 

(c)(4)(xi), for gas flow meters;

(viii) The quality-assurance records under §75.59(a) of 

this chapter, paragraphs (a)(1) through (a)(12) and (a)(15), for 

CEMS;

(ix) The quality-assurance records under §75.59(a) of this 

chapter, paragraphs (b)(1) through (b)(4), for fuel flow meters; 

and

(x) Records of data acquisition and handling system (DAHS) 

verification under §75.59(e) of this chapter.

(c) You must keep records of the calculations you performed 

to determine the hourly and total CO2 mass emissions (tons) for:

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

(2) Each compliance period, including, each 12-operatingmonth compliance period.

(d) Consistent with §60.5520, you must keep records of the 

applicable data recorded and calculations performed that you 

used to determine your affected EGU’s gross or net energy 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 
Page 739 of 764

standard in Table 1 or 2 of this subpart.

(g) You must keep records of the calculations you 

performed to determine any site-specific 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 3 years after the 

date of conclusion of each compliance period. 

(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. Records that are accessible from a central location by a 

computer or other means that instantly provide access at the 

site meet this requirement. You may maintain the records off

site 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 EGU?

Notwithstanding any other provision of this chapter, 

certain parts of the General Provisions in §60.1 through 60.19, 

listed in Table 3 to this subpart, do not apply to your affected 

EGU.

§60.5575 Who implements and enforces this subpart?
Page 740 of 764

(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, 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 
Page 741 of 764

have the meaning given them in the Clean Air Act and in subpart 

A (General Provisions of this part).

Annual capacity factor means the ratio between the actual 

heat input to an EGU during a calendar year and the potential 

heat input to the EGU had it been operated for 8,760 hours 

during a calendar year at the base load rating.

Base load rating means the maximum amount of heat input 

(fuel) that an EGU can combust on a steady state basis, as 

determined by the physical design and characteristics of the EGU 

at ISO conditions. For a stationary combustion turbine, base 

load rating includes the heat input from duct burners.

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.
Page 742 of 764

Combined cycle unit 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 (HRSG) to generate additional electricity.

Combined heat and power unit or CHP unit, (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 output from the same primary energy source.

Design efficiency means the rated overall net efficiency 

(e.g., electric plus useful thermal output) on a lower heating 

value basis at the base load rating, at ISO conditions, and at 

the maximum useful thermal output (e.g., CHP unit with 

condensing steam turbines would determine the design efficiency 

at the maximum level of extraction and/or bypass). Design 

efficiency shall be determined using one of the following 

methods: ASME PTC 22 Gas Turbines (incorporated by reference, 

see §60.17), ASME PTC 46 Overall Plant Performance (incorporated 

by reference, see §60.17) or ISO 2314:2009 Gas turbines –

acceptance tests (incorporated by reference, see §60.17).

Distillate oil means fuel oils that 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 numbers 
Page 743 of 764

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).

Electric Generating units or EGU means any steam generating 

unit, IGCC unit, or stationary combustion turbine that is 

subject to this rule (i.e., meets the applicability criteria)

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, the gross 

electric or direct mechanical output from both the EGU 

(including, but not limited to, output from steam turbine(s), 
Page 744 of 764

combustion turbine(s), and gas expander(s)) plus 100 percent of 

the useful thermal output.

(2) For steam generating units, the gross electric or 

mechanical output from the affected EGU(s) (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 100 percent of the useful thermal output;

(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 useful thermal output on a 

12-operating-month rolling average basis, the gross electric or 

mechanical output from the affected EGU (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 100 percent of the useful thermal output.

Heat recovery steam generating unit (HRSG) means an EGU 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 unit or IGCC means a 
Page 745 of 764

combined cycle stationary combustion turbine that is designed to 

burn fuels containing 50 percent (by heat input) or more solidderived fuel not meeting the definition of natural gas. The 

Administrator may waive the 50 percent solid-derived fuel 

requirement during periods of the gasification system 

construction, startup and commissioning, shutdown, or repair. No 

solid fuel is directly burned in the EGU 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 EGU(s), generate electricity 

and/or thermal energy, or to enhance the performance of the 

affected EGU. 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. Finally, natural gas does not 
Page 746 of 764

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 CO2 content or 

heating value.

Net-electric sales means 

(1) The gross electric sales to the utility power 

distribution system minus purchased power; 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 an annual basis, the gross electric sales to the 

utility power distribution system minus purchased power of the 

thermal host EGU or facilities. 

(3) Electricity supplied to other facilities that produce 

electricity to offset auxiliary loads are included when 

calculating net-electric sales.

(4) Electric sales that that result from a system emergency 

are not 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 
Page 747 of 764

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 the 

affected EGU plus 100 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 useful 

thermal output on a 12-operating-month rolling average basis, 

the net electric or mechanical output from the affected EGU 

divided by 0.95, plus 100 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 EGU at any time.
Page 748 of 764

Petroleum means crude oil or a fuel derived from crude 

oil, including, but not limited to, distillate and residual 

oil.

Potential electric output means 33 percent or the base 

load rating design efficiency at the maximum electric 

production rate (e.g., CHP units with condensing steam 

turbines will operate at maximum electric production), 

whichever is greater, multiplied by the base load rating 

(expressed in MMBtu/h) of the EGU, 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 EGU 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 50 Btu/lb.

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. 
Page 749 of 764

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, post-combustion emission 

control technology, and any ancillary components and subcomponents 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) plus any integrated equipment 

that provides electricity or useful thermal output to the 

affected EGU(s) or auxiliary equipment.

System emergency means any abnormal system condition that 

the Regional Transmission Organizations (RTO), Independent 
Page 750 of 764

System Operators (ISO) or control area Administrator determines 

requires immediate automatic or manual action to prevent or 

limit loss of transmission facilities or generators that could 

adversely affect the reliability of the power system and 

therefore call for maximum generation resources to operate in 

the affected area, or for the specific affected facility to 

operate to avert loss of load

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 EGU, to 

directly enhance the performance of the affected EGU (e.g., 

economizer output is not useful thermal output, but thermal 

energy used to reduce fuel moisture is considered useful thermal 

output), or to supply energy to a pollution control device at 

the affected EGU. Useful thermal output for affected EGU(s) with 

no condensate return (or other thermal energy input to the 

affected EGU(s)) or where measuring the energy in the condensate

(or other thermal energy input to the affected EGU(s)) would not 

meaningfully impact the emission rate calculation is measured 

against the energy in the thermal output at SATP conditions. 

Affected EGU(s) with meaningful energy in the condensate return 

(or other thermal energy input to the affected EGU) must measure 
Page 751 of 764

the energy in the condensate and subtract that energy relative 

to SATP conditions from the measured thermal output. 

System emergency means any abnormal system condition that 

the Regional Transmission Organizations (RTO), Independent 

System Operators (ISO) or control area Administrator determines 

requires immediate automatic or manual action to prevent or 

limit loss of transmission facilities or generators that could 

adversely affect the reliability of the power system and 

therefore call for maximum generation resources to operate in 

the affected area, or for the specific affected facility to 

operate to avert loss of load.

Valid data means quality-assured data generated by 

continuous monitoring systems that are installed, operated, and 

maintained according to part 75 of this chapter. For CEMS, the 

initial certification requirements in §75.20 of this chapter and 

appendix A to part 75 of this chapter must be met before 

quality-assured data are reported under this subpart; for ongoing quality assurance, the daily, quarterly, and 

semiannual/annual test requirements in sections 2.1, 2.2, and 

2.3 of appendix B to part 75 of this chapter must be met and the 

data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of 

appendix B to part 75 of this chapter apply. For fuel flow 

meters, the initial certification requirements in section 2.1.5 

of appendix D to part 75 of this chapter must be met before 
Page 752 of 764

quality-assured data are reported under this subpart (except for 

qualifying commercial billing meters under section 2.1.4.2 of 

appendix D), and for on-going quality assurance, the provisions 

in section 2.1.6 of appendix D to part 75 of this chapter apply 

(except for qualifying commercial billing meters). 

Violation means a specified averaging period over which the 

CO2 emissions rate is higher than the applicable emissions 

standard located in Table 1 or Table 2 of this subpart.
Page 753 of 764

Table 1 of Subpart TTTT of Part 60 – CO2 Emission Standards for 

Affected Steam Generating Units and Integrated Gasification 

Combined Cycle Facilities that Commenced Construction after 

January 8, 2014 and Reconstruction or Modification after June 

18, 2014 

Note: numerical values of 1,000 or greater have a minimum of 3 

significant figures and numerical values of less than 1,000 have 

a minimum of 2 significant figures

Affected EGU CO2 Emission Standard

Newly constructed steam 

generating unit or integrated 

gasification combined cycle 

(IGCC)

640 kg CO2/MWh of gross energy 

output (1,400 lb CO2/MWh)

Reconstructed steam generating 

unit or IGCC that has base load 

rating of 2,100 GJ/h (2,000 

MMBtu/h) or less

910 kg of CO2 per MWh of gross 

energy output (2,000 lb 

CO2/MWh)

Reconstructed steam generating 

unit or IGCC that has a base 

load rating greater than 2,100 

GJ/h (2,000 MMBtu/h)

820 kg of CO2 per MWh of gross 

energy output (1,800 lb 

CO2/MWh) 

Modified steam generating unit 

or IGCC

A unit-specific emission limit 

determined by the unit’s best 

historical annual CO2 emission 

rate (from 2002 to the date of 

the modification); the 

emission limit will be no 

lower than:

1. 1,800 lb CO2/MWh-gross for 

units with a base load 

rating greater than 2,000 

MMBtu/h; or

2. 2,000 lb CO2/MWh-gross for 

units with a base load 

rating of 2,000 MMBtu/h or 

less.
Page 754 of 764

Table 2 of Subpart TTTT of Part 60 – CO2 Emission Standards for 

Affected Stationary Combustion Turbines that Commenced 

Construction after January 8, 2014 and Reconstruction after June 

18, 2014 (net energy output-based standards applicable as 

approved by the Administrator)

Note: numerical values of 1,000 or greater have a minimum of 3 

significant figures and numerical values of less than 1,000 have 

a minimum of 2 significant figures

Affected EGU CO2 Emission Standard614

Newly constructed or

reconstructed stationary 

combustion turbine that 

supplies more than its design 

efficiency times its potential 

electric output as net-electric 

sales on a 3 year rolling 

average basis and combusts more 

than 90% natural gas on a heat 

input basis on a 12-operatingmonth rolling average basis.

450 kg of CO2 per MWh of gross 

energy output (1,000 lb 

CO2/MWh); or

470 kilograms (kg) of CO2 per 

megawatt-hour (MWh) of net 

energy output (1,030 lb/MWh) 

Newly constructed or 

reconstructed stationary 

combustion turbine that 

supplies its design efficiency

times its potential electric 

output or less as net-electric 

sales on a 3 year rolling 

average basis and combusts more 

than 90% natural gas on a heat 

input basis on a 12-operatingmonth rolling average basis.

50 kg CO2 per gigajoule (GJ) of 

heat input (120 lb CO2/MMBtu) 

Newly constructed and 

reconstructed stationary 

combustion turbine that 

combusts 90% or less natural 

gas on a heat input basis on a 

12-operating-month rolling 

average basis.

50 kg CO2/GJ of heat input (120 

lb/MMBtu) to 69 kg CO2/GJ of 

heat input (160 lb/MMBtu) as 

determined by the procedures 

in § 60.5525

 

614 See procedures for establishing and revising the compliance 

option under § 60.5520.
Page 755 of 764

Table 3 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

Does not apply to 

information 

reported 

electronically 

through ECMPS. 

Duplicate 

submittals are not 

required. 

§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 

notifications in 

60.7(a)(1) and 

(a)(3) and to keep 

records of 

malfunctions in 

§60.7(b), if 

applicable

§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 No

All monitoring is 

done according to 

Part 75 
Page 756 of 764

§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

Does not apply to 

notifications 

under

§75.61 or to 

information 

reported through 

ECMPS.
Page 757 of 764

PART 70— STATE OPERATING PERMIT PROGRAMS

4. The authority citation for part 70 continues to read as 

follows:

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

5. Section 70.2 is amended by revising the introductory 

text, removing “or” from the end of paragraph (2), adding “or” 

to the end of paragraph (3), and adding paragraph (4) to the 

definition of “Regulated pollutant (for presumptive fee 

calculation).”

The revision and additions read as follows:

§70.2 Definitions.

* * * * *

Regulated pollutant (for presumptive fee calculation),

which is used only for purposes of § 70.9(b)(2), means any 

regulated air pollutant except the following:

* * * * *

(4) Greenhouse gases.

* * * * *

6. Section 70.9 is amended by revising paragraph (b)(2)(i), 

and by adding paragraph (b)(2)(v) to read as follows:

§70.9 Fee determination and certification.

* * * * *

(b) * * *

(2)(i) The Administrator will presume that the fee schedule 
Page 758 of 764

meets the requirements of paragraph (b)(1) of this section if it 

would result in the collection and retention of an amount not 

less than $25 per year [as adjusted pursuant to the criteria set 

forth in paragraph (b)(2)(iv) of this section] times the total 

tons of the actual emissions of each regulated pollutant (for 

presumptive fee calculation) emitted from part 70 sources and 

any GHG cost adjustment required under paragraph (b)(2)(v) of 

this section.

* * * * *

(v) GHG cost adjustment. The amount calculated in paragraph 

(b)(2)(i) of this section shall be increased by the GHG cost 

adjustment determined as follows: For each activity identified 

in the following table, multiply the number of activities 

performed by the permitting authority by the burden hours per 

activity, and then calculate a total number of burden hours for 

all activities. Next, multiply the burden hours by the average 

cost of staff time, including wages, employee benefits and 

overhead.

Activity Burden 

hours per 

activity

GHG completeness determination (for initial permit 

or updated application)

GHG evaluation for a permit modification or related 

permit action

GHG evaluation at permit renewal

43

7

10

* * * * *
Page 759 of 764

PART 71— FEDERAL OPERATING PERMIT PROGRAMS

7. The authority citation for part 71 continues to read as 

follows:

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

8. Section 71.2 is amended by removing “or” from the end of 

paragraph (2), adding “or” to the end of paragraph (3), and 

adding paragraph (4) to the definition of “Regulated pollutant 

(for fee calculation).” 

The revisions and additions read as follows:

§71.2 Definitions.

* * * * *

Regulated pollutant (for fee calculation), which is used 

only for purposes of §71.9(c), means any “regulated air 

pollutant” except the following:

* * * * *

(4) Greenhouse gases.

* * * * *

9. Section 71.9 is amended by:

a. Revising paragraphs (c)(1), (c)(2)(i), (c)(3), and 

(c)(4), and

b. Adding paragraph (c)(8).

The revisions and additions read as follows:

§71.9 Permit fees.

* * * * *
Page 760 of 764

(c) * * * 

(1) For part 71 programs that are administered by EPA, each 

part 71 source shall pay an annual fee which is the sum of: 

(i) $32 per ton (as adjusted pursuant to the criteria set 

forth in paragraph (n)(1) of this section) times the total tons 

of the actual emissions of each regulated pollutant (for fee 

calculation) emitted from the source, including fugitive 

emissions; and

(ii) Any GHG fee adjustment required under paragraph (c)(8) 

of this section. 

(2) * * *

(i) Where the EPA has not suspended its part 71 fee 

collection pursuant to paragraph (c)(2)(ii) of this section, the 

annual fee for each part 71 source shall be the sum of: 

(A) $24 per ton (as adjusted pursuant to the criteria set 

forth in paragraph (n)(1) of this section) times the total tons 

of the actual emissions of each regulated pollutant (for fee 

calculation) emitted from the source, including fugitive 

emissions; and 

(B) Any GHG fee adjustment required under paragraph (c)(8) 

of this section.

* * * * *
Page 761 of 764

(3) For part 71 programs that are administered by EPA with 

contractor assistance, the per ton fee shall vary depending on 

the extent of contractor involvement and the cost to EPA of 

contractor assistance. The EPA shall establish a per ton fee 

that is based on the contractor costs for the specific part 71 

program that is being administered, using the following 

formula:

Cost per ton=( E ×32)+[(1− E )×$ C ]

Where E represents EPA's proportion of total effort 

(expressed as a percentage of total effort) needed to administer 

the part 71 program, 1- E represents the contractor's effort, 

and C represents the contractor assistance cost on a per ton 

basis. C shall be computed by using the following formula:

C =[ B + T + N ] divided by 12,300,000

Where B represents the base cost (contractor costs), where 

T represents travel costs, and where N represents nonpersonnel 

data management and tracking costs. In addition, each part 71 

source shall pay a GHG fee adjustment for each activity as 

required under paragraph (c)(8) of this section.

(4) For programs that are delegated in part, the fee shall

be computed using the following formula:

Cost per ton=( E ×32)+( D ×24)+[(1− E − D )×$ C ]

Where E and D represent, respectively, the EPA and delegate 

agency proportions of total effort (expressed as a percentage of 
Page 762 of 764

total effort) needed to administer the part 71 program, 1− E − D

represents the contractor's effort, and C represents the 

contractor assistance cost on a per ton basis. C shall be 

computed using the formula for contractor assistance cost found 

in paragraph (c)(3) of this section and shall be zero if 

contractor assistance is not utilized. In addition, each part 

71 source shall pay a GHG fee adjustment for each activity as 

required under paragraph (c)(8) of this section.

* * * * *

(8) GHG fee adjustment. The annual fee shall be increased 

by a GHG fee adjustment for any source that has initiated an 

activity listed in the following table since the fee was last 

paid. The GHG fee adjustment shall be equal to the set fee 

provided in the table for each activity that has been initiated 

since the fee was last paid: 

Activity Set fee

GHG completeness determination (for initial permit 

or updated application)

GHG evaluation for a permit modification or related 

permit action 

GHG evaluation at permit renewal

$2,236

$364

$520

* * * * *

PART 98— MANDATORY GREENHOUSE GAS REPORTING
Page 763 of 764

10. The authority citation for part 98 is revised to read 

as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart PP—Suppliers of Carbon Dioxide

11. Section 98.426 is amended by adding paragraph (h) to 

read as follows:

§98.426 Data reporting requirements.

* * * * *

(h) If you capture a CO2stream from an electricity 

generating unit that is subject to subpart D of this part and 

transfer CO2 to any facilities that are subject to subpart RR of 

this part, you must:

(1) Report the facility identification number associated 

with the annual GHG report for the subpart D facility, 

(2) Report each facility identification number associated 

with the annual GHG reports for each subpart RR facility to 

which CO2 is transferred, and

(3) Report the annual quantity of CO2 in metric tons that 

is transferred to each subpart RR facility.

11. Section 98.427 is amended by adding paragraph (d) to 

read as follows:

§98.427 Records that must be retained.

* * * * *
Page 764 of 764

(d) Facilities subject to §98.426(h) must retain records of 

CO2 in metric tons that is transferred to each subpart RR 

facility.