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

6560-50

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60, 70, 71, and 98

[EPA-HQ-OAR-2013-0495; EPA-HQ-OAR-2013-0603; FRL-XXXX-XX-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. This action establishes 

separate standards of performance for fossil fuel-fired electric 

utility steam generating units and fossil fuel-fired 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 guidelines for 

states to use in developing plans to limit CO2 emissions from 

existing fossil fuel-fired EGUs. 
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DATES: This final rule is effective on [insert date 60 days 

after 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 

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-
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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

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
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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

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

MW Megawatt

MWe Megawatt Electrical

MWh Megawatt-hour

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
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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

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

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 
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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. Carbon Pollution Standards for Fossil Fuel-Fired Electric 

Utility Generating Units

G. Stakeholder Engagement and Public Comments on the Proposals

III. Regulatory Authority, Affected Sources 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

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

V. Rationale for Final Standards for Newly Constructed Fossil 

Fuel-fired Electric Utility Steam Generating Units

A. Factors Considered in Determining the BSER

B. Partial CCS as the BSER for Newly Constructed Steam 

Generating Units

C. Rationale for the Final Emission Standards

D. Post-Combustion CCS

E. Pre-Combustion CCS

F. Vendor Guarantees, Industry Statements, Academic Literature, 

and Commercial Availability

G. Response to Key Comments

H. Consideration of Costs

I. Key Comments Regarding EPA’s Consideration of Costs

J. Achievable Emission Reductions Utilizing Partial CCS

K. Further Development and Deployment of CCS Technology

L. Geologic and Geographic Considerations
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M. Final Requirements for Disposition of Captured CO2

N. Options That Were Considered but Were Ultimately Not 

Determined to Be the BSER

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, 

Modified, and Reconstructed Stationary Combustion Turbines

A. Applicability Requirements

B. Best System of Emission Reduction

C. Final Emission Standards

IX. Rationale for Final Standards for Newly Constructed, 

Modified, and Reconstructed Stationary Combustion Turbines

A. Applicability

B. Identification of the Best System of Emission Reduction

C. Achievability of the Final Standards

X. Summary of Other Final Requirements for Newly Constructed, 

Modified, and Reconstructed Fossil Fuel-fired 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. 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

XII. 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?
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G. What are the benefits of the final standards?

XIII. 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)

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

K. Congressional Review Act (CRA)

XIV. Statutory Authority

I. General Information

A. Executive Summary

1. Purpose of the Regulatory Action 

This action finalizes regulatory requirements to 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 
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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, EPA 

Administrator Gina McCarthy signed 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 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’ 

 

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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relationship to the factual record supporting the proposed rule. 

79 FR 10750 (February 26, 2014).

On June 2, 2014, Administrator McCarthy signed 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 34959 (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 turbines, (3) reconstructed fossil fuelfired steam generating units, and (4) reconstructed natural gasfired stationary combustion turbines.

In this action, the EPA is issuing final standards of 

performance to limit emissions of greenhouse gas (GHG) pollution 

manifested as CO2 from newly constructed, modified, and 

reconstructed fossil fuel-fired electric utility steam 

generating units and from newly constructed, modified, 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 
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60, subpart TTTT, a new subpart specifically created for CAA 

111(b) standards of performance for GHG emissions.

In a separate action that affects the same source category, 

under CAA section 111(d), the EPA is issuing final emission 

guidelines for states to use in developing plans to limit CO2

emissions from existing fossil fuel-fired EGUs. States must then 

submit plans to the EPA following a schedule set by the 

guidelines.

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 some 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 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, 
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2014. The final standards for modified and reconstructed fossil 

fuel-fired EGUs apply to those sources that modify or 

reconstruct on or after the date of publication of the proposed 

standards, June 18, 2014.

Table 1. Summary of BSER and Final Standards for Affected 

Sources

Affected 

Source

BSER Standard

Newly 

Constructed 

Fossil FuelFired Steam 

Generating 

Units

Partial carbon 

capture and 

storage (CCS)

1,400 lb CO2/MWh-gross.

Modified 

Fossil FuelFired Steam 

Generating 

Units

Most efficient 

generation at 

the affected 

source 

achievable 

through a 

combination of 

best operating 

practices and 

equipment 

upgrades 

Sources making modifications

resulting in an increase in 

potential 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 lower 

than:

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

sources with heat input > 2,000

MMBtu/h.

OR

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

sources with heat input ≤ 2,000 

MMBtu/h.

Reconstructed 

Fossil FuelFired Steam 

Most efficient 

generating 

technology

1. Sources with heat input > 2,000 

MMBtu/h are required to meet an 

emission limit of 1,800 lb 
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Generating 

Units

at the 

affected

source

(supercritical 

steam 

conditions for 

the larger; 

and 

subcritical 

conditions for 

the smaller)

CO2/MWh-gross.

2. Sources with heat input ≤ 2,000 

MMBtu/h are required to meet an 

emission limit of 2,000 lb 

CO2/MWh-gross.

Newly 

Constructed, 

Modified, and 

Reconstructed 

Fossil FuelFired 

Stationary 

Combustion 

Turbines

Efficient NGCC 

technology

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

2. 1,080 lb CO2/MWh-net

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

This action finalizes standards of performance for newly 

constructed fossil fuel-fired steam generating units2 based on

partial carbon capture and storage (CCS) which the EPA 

determines to be the BSER for these sources. After consideration 

of the wide range of comments, technical input received on the 

availability, technical feasibility, and cost of CCS 

implementation, and publicly available information about 

 

2 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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projects that are implementing or planning to implement CCS, the 

EPA remains convinced that CCS technology is available and 

technically feasible to implement at fossil fuel-fired steam 

generating units. However, the EPA’s final standard does 

recognize that the proposed standards should be adjusted to 

address legitimate concerns regarding the cost to implement the 

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-gross, a level that is less stringent than the 

proposed limitation (which was at 1,100 lb CO2/MWh-gross). This 

final standard reflects our identification of the BSER for such

units to be a lower level of partial CCS than was the basis of 

the proposed standards – one that we conclude better represents 

the requirement that the BSER technology be implementable at 

reasonable costs.

The EPA proposed and reaffirms here that this system is the 

BSER because CCS has been demonstrated to be technically 

feasible and is in use or under construction in various 

industrial sectors including power generation. 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. In addition, partial CCS
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designed to meet the final emission standard will promote 

implementation and further development of CCS technologies. A 

newly constructed conventional coal-fired utility boiler burning 

bituminous coal will be able to meet this standard of 

performance by capturing and storing approximately 20 percent of 

the CO2 produced from the facility. Many IGCC units will be able 

to meet the final standard of performance by capturing and 

storing less than 10 percent of the CO2 produced by the facility. 

All steam generating sources may also be able to meet the 

standard through alternative actions, such as the use of natural 

gas co-firing. 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 greenhouse gas 

emissions and supports technological innovation. The standard of 

1,400 lb CO2/MWh-gross 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 CCS as BSER can provide a path 

forward for fossil steam generation in the current market 

context. Numerous studies have found that few new fossil-fuel 

fired steam generating units will be constructed in the future 

for multiple reasons, including low electricity demand growth, 

highly competitive natural gas prices, and increases in the 
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supply of renewable energy. The EPA recognizes that in certain 

circumstances there may be interest in building fossil steam 

units despite these market conditions: in particular, to achieve 

or maintain fuel diversity within generating fleets and hedge 

against the possibility of natural gas prices far exceeding 

projections or to generate both power and chemicals, including

CO2 for use in enhanced oil recovery projects. As regulatory 

history has shown, identifying CCS as BSER in this rule will 

likely further boost research and developments in this 

technology, making its application even more efficacious and 

cost-effective – and providing a competitive, low emission 

future for fossil 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 potential hourly CO2

emissions of more than 10 percent when compared to the source’s 

potential in the previous 5 years). The EPA is not issuing 

standards, at this time, for steam generating units that 

implement “small modifications” (i.e., modifications resulting 

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

equal to 10 percent when compared to the source’s potential in 

the previous 5 years).

The standards of performance for the modified steam 

generating units that make large modifications are based on each 
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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). 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 cost-effectively at a 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 standard for reconstructed steam generating units

(i.e., 1,800 lb CO2/MWh-gross for units with heat input greater 

than 2,000 MMBtu/h and 2,000 lb CO2/MWh-gross 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 plan). We also 

suggested that for units that undertake modifications prior to 
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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, modified 

steam generating sources that make modifications resulting in an 

potential increase of hourly CO2 emissions of less than or equal 

to 10 percent. As we indicated in the proposal, the EPA has been 

notified of very few modifications for criteria pollutant 

emissions from the power sector to which NSPS requirements have 

applied. As such, we expect that there will be few 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 that may result from these changes. In 

particular, we do not have sufficient information about the 

types of modifications 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 
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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 of performance 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.)3 The emission 

standard for these sources is 1,800 lb CO2/MWh-gross for large 

sources, (i.e. those with a heat input rating of greater than 

2,000 MMBtu/h) or 2,000 lb CO2/MWh-gross 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 

technology options such as natural gas co-firing.

b. Stationary combustion turbines. This action also finalizes 

standards of performance for newly constructed, modified, and 

reconstructed stationary combustion turbines. The EPA originally 

 

3 Steam with higher temperature and pressure has more thermal 

energy that can be more efficiently converted to electrical 

energy.
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proposed that newly constructed, modified, or reconstructed 

stationary combustion turbines would be subject to a standard of 

performance if they are constructed for the purpose of and 

actually sell one-third or more of their potential electric 

output and 219,000 MWh to the grid. Later, in the June 2014

proposal for modified and reconstructed sources, the EPA 

solicited comment on alternative approaches, including 

eliminating the 219,000 MWh electric sales criterion, the 

constructed for the purpose of criterion, and replacing the onethird sales criterion with an approach that would allow netelectric sales up to the design efficiency of the combustion 

turbine being installed multiplied by its potential electric 

output before a standard would apply. These proposed 

applicability requirements were intended to exclude combustion 

turbines that are used for the purpose of meeting peak power 

demand (i.e., “peaking units”) as opposed to those that are used 

to meet intermediate or base load power demand. 

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

two approaches put forward in the June 2014 proposal. For newly 

constructed, modified, or reconstructed stationary combustion 

turbines the EPA is finalizing a standard of 1,000 lb CO2/MWhgross based on modern, efficient natural gas combined cycled 

(NGCC) technology as the BSER. However, the final applicability 

excludes units subject to a federally enforceable permit that 
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restrict annual net-electric sales to the design net efficiency

of the combustion turbine (not to exceed 40 percent) multiplied 

by the potential electric output of the combustion turbine. For 

example, a stationary combustion turbine with a design net 

efficiency of 38 percent (on a higher heating value (HHV) basis)

would be able to request a permit restriction to allow it to 

sell up to 38 percent of its potential electric output without 

becoming subject to this final standard.

4

The EPA previously proposed to divide intermediate and base 

load stationary combustion turbines into two subcategories based 

on their size (as determined by heat input rating) and to set 

separate standards of performance for each of those 

subcategories. Based on our review of the comments on the 

proposed subcategories and standards and additional data 

analysis, however, we have determined that there is no need to 

set separate standards for different sizes of combustion 

turbines. The EPA has determined that all sizes of affected 

newly constructed, modified, and reconstructed stationary 

combustion turbines will be able to achieve the final standard.

 

4 A turbine with a HHV design net efficiency of 45 percent would 

be allowed to sell up to 40 percent of its potential electric 

output before it would be subject to this final standard. A 

stationary combustion turbine with a HHV design net efficiency 

of 30 percent would be allowed to sell up to 30 percent of its 

potential electric output before it would be subject to this 

final standard.
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Stationary combustion turbines that are physically 

incapable of combusting natural gas, such as turbines in certain 

non-continental locations or in remote locations that lack 

access to a natural gas pipeline, will be exempt from the 

standard entirely.

A more detailed discussion of the final standards of 

performance, 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 

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

units built between now and 2020 would have CCS, even in the 
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absence of this rule. 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.5 However, 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 coalfired unit without CCS. 

As explained in the RIA for this final rule and further 

below, the EPA has been notified of few power sector NSPS 

modifications or reconstructions; and, based on that experience,

the EPA expects that few EGUs will trigger either the 

modification or the 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?

 

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

model year of 2020.
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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 

affected by this action. To determine whether your facility, 
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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 federal register]. 

Under section 307(d)(7)(B) of the CAA, only an objection to this 

final rule that was raised with reasonable specificity during 

the period for public comment can be raised during judicial 
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review. Moreover, under section 307(b)(2) of the CAA, the 

requirements established by this final rule may not be 

challenged separately in any civil or criminal proceedings 

brought by 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 for us 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 to us 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 

natural gas-fired 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 authority to regulate CO2 and EGUs,

identifies affected sources, and describes the source 

categories. Section IV provides a summary of the final standards 

for newly constructed, modified, and reconstructed fossil fuelfired 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, 

modified, and reconstructed combustion turbines. 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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Interactions with other EPA programs and rules are described in 

Section XI. Projected impacts of the final action are then 

described in Section XII, followed by a discussion of statutory 

and executive order reviews in Section XIII and the statutory 

authority for this action in Section XIV. 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, explain the uniqueness of the utility power sector, and 

describe recent and continuing trends and transitions in this 

sector. 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 

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
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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.”6

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).7 In the 

Endangerment Finding, the Administrator found that the current, 

elevated concentrations of GHGs in the atmosphere—already at 

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

 

6 National Research Council, Climate Stabilization Targets, p.3. 

7 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases Under Section 202(a) of the Clean Air Act,” 74 Fed. Reg. 

66,496 (Dec. 15, 2009) (“Endangerment Finding”).
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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., including 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 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 
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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 flooding damage to property or even loss of land due 

to inundation or erosion; as well as 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 

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.
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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 

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 
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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 VIII.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. 

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 disease-
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carriers 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 

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 
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to exposed locations along ocean, lake, or river shorelines.”8 

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 

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. 

 

8 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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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.9 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 

Earth history.”10 Because of these unprecedented changes, several 

assessments state that we may be approaching critical, poorly 

understood thresholds: as stated in the NRC assessment 

Understanding Earth’s Deep Past, “As Earth continues to warm, it 

 

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

1.

10 Id., p.138.
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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.” 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 AR5 projects 

that 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 impacts 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 
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has been summarized as wet areas getting wetter and dry regions 

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 

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 carbon dioxide and 

methane released from thawing permafrost, will also amplify

future warming. 
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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] 

global average sea-level rise by 2100,”11 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 

 

11 NRC, 2011: National Security Implications of Climate Change 

for U.S. Naval Forces. The National Academies Press, p. 28.
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“[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.”12 Also, because of the inertia of the oceans, sea level 

rise will continue for centuries after greenhouse gas 

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: according to the NCA, some recent research 

has suggested that even present day carbon dioxide 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 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 United States. Particularly in Alaska, critical

infrastructure and traditional livelihoods are threatened by 

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

 

12 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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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.”13 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 

through impacts on livelihoods, reductions in crop yields, or 

destruction of homes and indirectly through, for example, 

increased food prices and food insecurity.”14

Carbon dioxide 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 

 

13 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.

14 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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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 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. 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 carbon dioxide emissions; the rate of 

change exceeds any known to have occurred for at least the past 

hundreds of thousands of years.”15 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.”16 

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 

 

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

the Challenges of a Changing Ocean. The National Academies 

Press, p. 5.

16 Ibid.
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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 

cites Egypt and Pakistan as two case studies of potential 

security issues linked to climate change within the next 10 

years17; and 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 

 

17 NRC, 2011: National Security Implications of Climate Change 

for U.S. Naval Forces. The National Academies Press, p. 121 (“Of 

the many places in the world where climate dynamics might induce 

globally consequential disruption within a decade, Egypt is a 

principal possibility.”); p. 122 (“Pakistan presents a clear 

example of a country where social dynamics and susceptibility to 

harm from climate events combine to create a potentially 

unstable situation.”).
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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 

1,400 years. U.S. average temperatures have similarly increased 

by 1.3 to 1.9 degrees 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 

Gt/year of ice 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 increased substantially in 

recent years, to 215 Gt/year and 147 Gt/year respectively since 

2002. 360 Gt of ice melt will 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 
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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.18 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 

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.19 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 1993.20 And 2014 was the 

 

18

ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.txt

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

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

in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1-S238.
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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 2002.21 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 

reasons “why it is imprudent to delay actions that at least 

begin the process of substantially reducing emissions.”22 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.

 

21 http://www.ncdc.noaa.gov/sotc/global/2014/13

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

Press.
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 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 8 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, 

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 US 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 
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flooding, and intense precipitation events. 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 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 
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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. 

The Southeast is exceptionally vulnerable to sea level 

rise, extreme heat events, hurricanes, and decreased water 

availability. Major consequences of further warming include 

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 are generally smaller than 

for other regions of the United States, projected warming for 

interior states of the region are larger than coastal regions by 

1 °F to 2 °F. Projections further suggest that globally there 

will be fewer tropical storms, 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 additional impacts on coastal highways, wetlands, and 

energy and water supplies.

In the Northwest, temperatures increased by about 1.3oF 

between 1895 and 2011. A small average increase in precipitation 

was observed over this time period. However, warming 
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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 

reduced streamflows during summer months. Drier conditions have 

increased the extent of wildfires in the region.

Average annual temperatures are projected to increase by 

3.3oF to 9.7oF by the end of the century (depending on future 

global greenhouse gas emissions), with the greatest warming is 

expected during the summer. Continued increases in global 

greenhouse gas emissions are projected to result in up to a 30

percent decrease in summer precipitation. Earlier snowpack melt 

and lower summer streamflows 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. Forest pests are 

expected to spread and wildfires burn larger areas. Other highelevation 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 
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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 

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 

greenhouse gas 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 
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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, 

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 
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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 

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. Climate change will also have impacts on the highvalue 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. 

Precipitation generally increased over the last century, with 
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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 Plain 

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 

annual temperatures over the past 130 years is the fastest in 
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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 

have exhibited a warming trend, with temperatures from the 
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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 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 to 50 percent from present levels by 2100. 

The NCA also discussed impacts that occur along the coasts 

and in the oceans adjacent to many regions, and noted that other 
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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 electric utility generating units (EGUs) 

are by far the largest emitters of GHGs among stationary sources 

in the U.S., primarily in the form of CO2. Among fossil fuelfired 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 Sinks23 (the U.S. GHG Inventory). 

The EPA implements a separate program under 40 CFR part 98 

called the Greenhouse Gas Reporting Program24 (GHGRP) that 

requires emitting facilities over threshold amounts of GHGs to 

report their emissions to EPA annually. Using data from the 

GHGRP, this section also places emissions from fossil fuel-fired 

EGUs in the context of the total 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 

 

23 “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

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

http://www.epa.gov/ghgreporting/ghgdata/reportingdatasets.html.
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on Climate Change (UNFCCC). This inventory, which includes 

recent trends, is organized by industrial sectors. It provides 

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

anthropogenic emissions and sinks25 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 CO2 Eq.))26

SECTOR 1990 2005 2013

Energy27

 

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 

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 

 

25 Sinks are a physical unit or process that stores GHGs, such as 

forests or underground or deep sea reservoirs of carbon dioxide.

26 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 

27 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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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.28 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.29 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)

30

 

28 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

29 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

30 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.

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 
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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 Greenhouse Gas Reporting Program (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, carbon dioxide 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.

Table 5. Direct GHG Emissions Reported to GHGRP by Largest 

Emitting Industrial Sectors (MMT CO2e)31

 

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

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

 - from petroleum

 

97.5 

 

97.9 22.4 

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 
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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 2013.32

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 

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 provided by other types of generation 

including nuclear, and renewables such as wind, solar, and 

 

32 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.

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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hydroelectric power. Coal provided the largest percentage of the 

fossil fuel generation.33 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.34. 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).35 From 2007 to 2014, use of lowerand zero-carbon energy sources has grown, while other major 

energy sources such as coal and oil have experienced declines. 

Renewable electricity generation, including from large hydroelectric projects, grew from 8 percent to 13 percent over that 

time period.36 Between 2000 and 2013, approximately 90 percent of 

 

33 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.

34 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.

35 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.

36 Bloomberg New Energy Finance and the Business Council for 

Sustainable Energy, 2015 Factbook: Sustainable Energy in 

America, at 16 (2015), available at
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new power generation capacity built in the U.S. has come in the 

form of natural gas or renewable energy facilities.37 In 2015, 

the U.S. Energy Information Administration’s (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.38 

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 nonfossil 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. For example, the average age of 

U.S. coal steam units in 2015 is 45.39 In its 2013 Report Card 

 

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

erica%20Factbook.pdf.

37 Information Administration, Electricity: Form EIA-860 detailed 

data (Feb. 17, 2015), available at

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

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

Final Release, available at

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

numbers include projects that are under development and modelprojected nuclear, coal, and NGCC projects.

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

NEEDS inventory (a “snapshot” of the sector in 2016), and adding 

back units with actual/planned retirements in 2012-2016. See

http://www.epa.gov/airmarkets/documents/ipm/needs_v514.xlsx.
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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.”40 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.”41 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 

reliably meet electricity demand, but also how to meet 

electricity demand reliably and cost-effectively42 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

 

40 American Society for Civil Engineers, 2013 Report Card for 

America’s Infrastructure (2013), available at

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

41 American Society for Civil Engineers, 2013 Report Card for 

America’s Infrastructure (2013), available at

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

42 Business Council for Sustainable Energy Comments in Docket Id. 

No. EPA-HQ-OAR-2013-0602 at 2 (Nov. 19, 2014).
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2004 and 2014.43 In 2014, natural gas accounted for approximately 

27 percent of net generation.44 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 2040.45

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 

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).46 QFs were either cogeneration 

 

43 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.

44 Id.

45 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.

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

Systems, IEEE Press, at 220-221 (2d ed. 2010).
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facilities47 or small generation resources that use renewables 

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

as their primary fuels.48 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.49 In its AEO 2015 Reference case, EIA found 

that renewable energy will account for 38 percent of the overall 

growth in electricity generation from 2013 to 2040.50 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 2040.51

Price pressures caused by oil embargoes in the 1970s also 

brought the issues of conservation and energy efficiency to the 

 

47 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).

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

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

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

Outlook 2014 with Projections to 2040, at LR-5 (2014). 

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

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

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

Outlook 2015 with Projections to 2040, at 24-25(2015).
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forefront of U.S. energy policy.52 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.”53 

Energy efficiency has been utilized to meet energy demand to 

varying levels since that time. As of April 2014, 25 states54

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

 

52 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.

53 Edison Electric Institute, Making a Business of Energy 

Efficiency: Sustainable Business Models for Utilities, at 1 

(2007), available at 

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

/Documents/Making_Business_Energy_Efficiency.pdf.

54 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.
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targets, or energy efficiency resource standards (EERS).”55 

Funding for energy efficiency programs has grown rapidly in 

recent years, with budgets for electric efficiency programs 

totaling $5.9 billion in 2012.56

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.

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 used to produce power using a steam 

turbine (the steam cycle). Combining these generation cycles 

 

55 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.

56 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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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). 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 and hydrogen, 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 
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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.57

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 adopted 

incentives for electric generation from renewable energy sources 

and loan guarantees for 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.58

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

most widely-used fossil fuel for new construction of electric 

 

57 Levelized Cost of New Generation Resources in the Annual 

Energy Outlook 2011 

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

58 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.
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generating capacity through 2020, 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, two other projects, Summit Power's Texas Clean 

Energy Project (TCEP) and the Hydrogen Energy California Project 

(HECA) – both of which will deploy IGCC with CCS – continue as 

viable projects.

59 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 

that few, if any, new coal-fired EGUs would be built in this 

decade and that those that are built would have CCS.60 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, 

 

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

Houston Chronicle (April 1, 2015).

60 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.
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however, that a variety of factors may come into play in a 

decision to build new power generation and we want to ensure 

there are standards in place to make sure that whatever fuel is 

burned is done so in a way that minimizes CO2 emissions and 

continues to encourage the development of innovative 

technologies into the future, as Congress intended with CAA 

section 111.61

4. Energy Sector Modeling

Various energy sector modeling efforts, including 

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

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 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.62 The current 

report, AEO 201563, (i) shows that a modest amount of coal-fired 

 

61 These sources received federal assistance under EPAct 2005. 

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.

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

63 Energy Information Administration’s Annual Energy Outlook for 

2015, Final Release available at 

http://www.eia.gov/forecasts/aeo/index.cfm.
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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 case64, 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. Similarly, 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 2020.65

Specifically, the AEO 2015 projects the need for 28.4 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 modelprojected 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 10.7 GW of new coal-fired capacity, 5.5 GW of new 

nuclear capacity, and 14.2 GW of new NGCC capacity. The EPA 

 

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

baseline assumptions for economic growth, fuel supply, 

technology, and other key inputs.

65 Annual Energy Outlook 2010, 2011, 2012, and 2013.
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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 

impacted by this notice). The AEO 2015 also projects an 

additional 8 GW of new base load capacity additions, which are 

model-projected (unplanned). This consists of 7.7 GW of new NGCC 

capacity, and 0.3 GW of new coal equipped with CCS (incentivized 

with some government funding). Therefore, the AEO 2015 

projection suggests that this final rule would only impact small 

amounts of new power generating capacity through 2020, all of 

which is expected to already meet the emissions standards 

without incurring further control costs. In AEO 2015, 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 standard 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 predict 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, 
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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.66 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 

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. These IRPs indicate that companies are

focused on demand-side management programs to lower future 

electricity demand and 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 

 

66 http://www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html#documentation.
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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 these IRPs, the EPA acknowledges that a small number of 

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

While 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 

greenhouse gases (GHGs)67 meet the definition of “air pollutant” 

 

67 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).
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in the CAA,68 and premised its decision in AEP v. Connecticut69

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 

new stationary sources (including newly constructed, modified 

and reconstructed sources).70 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 111.71 The EPA listed the two source 

categories at issue here in the 1970s: The EPA listed fossil 

fuel-fired electric steam generating units in 1971;

72 and 

combustion turbines in 1977.

73

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

and then promulgates “standards of performance” for “new 

 

68 549 U.S. 497, 520 (2007).

69 131 S.Ct. 2527, 2537-38 (2011).

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

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

72 36 FR 5931 (March 31, 1971).

73 42 FR 53657 (October 3, 1977).
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sources” in the category.74 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.75 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 

pollutant not previously emitted.”76 The EPA, through 

regulations, has determined that certain types of changes are 

exempt from consideration as a modification.77

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.78

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

as “a standard for emissions of air pollutants which reflects 

 

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

75 CAA section 111(a)(2).

76 CAA section 111(a)(4).

77 40 CFR 60.2, 60.14(e).

78 40 CFR 60.15.
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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 nonair quality health and environmental impact and energy 

requirements) the Administrator determines has been adequately 

demonstrated.” This definition makes clear that the standard of 

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 which 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 

which 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.79 Rather, sources generally may select any measure 

or combination of measures that will achieve the emissions level 

of the standard.80 In establishing standards of performance, the 

 

79 CAA sections 111 (b)(5) and (h).

80 CAA section 111(b)(5).
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EPA has significant discretion to create subcategories based on 

source type, class or size.81

The text and legislative history of CAA section 111, as 

well as relevant court decisions identify the factors for the 

EPA 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 

the EPA promulgates based on the system of emission reduction 

must be achievable. In addition, the EPA must consider the 

amount of emissions reductions that the system would generate, 

along with considerations concerning energy and non-air quality 

pollutants. 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 that as a result, the EPA 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.

 

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

under CAA section 111 to set cost-effective emission standards 

that ensure 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 

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 sources 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),82 and promulgated the first set of 

standards of performance for sources in that category, which it 

codified in subpart D.83 In 1977, the EPA initially included 

 

82 36 FR 5931 (March 31, 1971)

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

Generators for Which Construction Is Commenced After August 17, 
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fossil fuel-fired combustion turbines in a category that the EPA 

listed under CAA section 111(b)(1)(A),84 and the EPA promulgated 

standards of performance for that source category in 1979, which 

the EPA codified in subpart GG.85

The EPA has revised those regulations, and in some 

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

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.86 In 2006, the EPA 

created subpart KKKK, ”Standards of Performance for Stationary 

Combustion Turbines,” which applied to certain sources 

 

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

46.

84 42 FR 53657 (October 3, 1977).

85 “Standards of Performance for Electric Utility Steam 

Generating Units for Which Construction is Commenced After 

September 18, 1978,” 44 FR 33580 (June 11, 1979).

86 44 FR 33580 (June 11, 1979)
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previously regulated in subparts Da and GG.

87 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 no standards of performance for GHG emissions.88

Petitioners sought judicial review of the rule by the D.C. 

Circuit, contending, among other issues, that the rule was 

required to include standards of performance for GHG emissions 

from EGUs.89 The January 8, 2014 preamble to the proposed CO2

standards for new EGUs90 includes a discussion of the GHG-related 

litigation of the 2006 Final Rule as well as other GHGassociated litigation.

F. Carbon Pollution Standards for Fossil Fuel-Fired Electric 

Utility Generating Units 

On April 13, 2012, the EPA initially proposed standards 

under CAA section 111 for newly constructed fossil fuel-fired 

 

87 71 FR 38497 (July 6, 2006), as amended at 74 FR 11861 (March 

20, 2009).

88 ”Standards of Performance for Electric Utility Steam 

Generating Units, Industrial-Commercial-Institutional Steam 

Generating Units, and Small Industrial-Commercial-Institutional 

Steam Generating Units, Final Rule.” 71 FR 9866 (February 27, 

2006).

89 State of New York, et al. v. EPA, No. 06–1322. 

90 79 FR 1430
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electric utility steam generating 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 

FR 10750). Through the NODA and the 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)91, 

including how the provisions may affect the rationale for the 

EPA’s proposed determination that partial CCS is the best system 

 

91 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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of emission reduction adequately demonstrated for fossil fuelfired 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 34959; 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.

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 
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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 

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, many of which have been 

utilities and industry representatives directly related to the 

electricity sector. The agency also met with energy industries 
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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 help 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, and 

religious organizations.

The EPA received more than 2.5 million comments submitted 

in response to the original April 2012 proposal for newly 

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 
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responsive to many stakeholder concerns and that enhance the 

rule. This preamble and the Response to Comments (RTC) document 

summarize and provide our responses to the comments received by 

the agency. 

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 offered 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 

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 

partial CCS was the BSER for newly constructed fossil fuel-fired 

steam generating EGUs, the level of the CO2 standard based on 
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partial CCS, the criteria that defines 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

28, 2014. These hearings also addressed 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 
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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 

combustion turbines described above (e.g., applicability 

criteria and subcategories based on turbine size). 

III. Regulatory Authority, Affected Sources 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 for all new and modified 

affected EGUs in new subpart TTTT of part 60 of Title 40 of the 

Code of Federal Regulations. In addition, we explain which 
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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 

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), 

regulations “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 were previously 

listed and regulated for other pollutants and now are being 

regulated for an additional pollutant. Because of this, there 
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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, 

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), 

231(a)(2)(A).

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 
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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 

standard, it is appropriate for EPA to exercise its authority to 

adopt a reasonable interpretation of this provision. Chevron 

U.S.A. Inc. v. NRDC, 467 U.S. 837, 843-44 (1984). 

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, 35858 (col. 3)(June 24, 

2008)(concluding 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).
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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 NOX, 

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-fired power plants, 

which are the major U.S. source of greenhouse gas air pollution, 

merits 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 

pollution and its impacts in taking those actions. In 2012, the 
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U.S. Court of Appeals for the D.C. Circuit upheld the finding 

and denial of petitions to reconsider. In addition, assessments 

from the NRC, the IPCC, and other organizations published after 

2010 lend further credence to the validity of the Endangerment 

Finding. As discussed below, no information that commenters have 

presented or that the EPA has reviewed provides a basis for 

rescinding that finding. 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 the fossilfired 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 

single new coal-fired power plant may amount to millions of tons 

each year. These facts provide a rational basis for regulating 

CO2 emissions from affected EGUs. 
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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,92 even if CAA section 

111 is interpreted to require that the EPA make endangerment and 

cause-or-contribute significantly findings as prerequisites for 

this rulemaking, then, so far as an endangerment finding is 

concerned, the fact that the EPA has recently made an 

endangerment finding for GHGs should suffice, and even if not,

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 GHGs 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 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 

 

92 79 FR 1430, 1455-56 (January 8, 2014).
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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). Accordingly, that 

approach would support an endangerment finding for this 

rulemaking.

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. In 

particular, as noted, combustion turbines alone emit 401 million 

metric tonnes per year, which is more than any other source 

category except for steam generators, and steam generators emit 

1,627 million metric tonnes per year. 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 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 
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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.

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, 

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 
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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 proposed 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 

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 
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not combining the two categories for purposes of standards of 

performance for other air pollutants.

Because these two source categories are pre-existing 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 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 finding that the combination of the two categories causes or 

contributes significantly to air pollution which may reasonably 

be anticipated to endanger public health or welfare.

As discussed above in the regulatory background of CAA 

section 111(b) actions on EGUs, there are several subparts in 

the code of federal regulations addressing EGUs (i.e., D, Da, 

GG, KKKK). This final action codifies all of the requirements 

promulgated in this final rule for the affected EGUs in a new 

subpart TTTT of 40 CFR part 60 and includes all GHG emission 

standards for the affected sources – electric utility steam 

generating units, as well as natural gas-fired stationary 

combustion turbines -- in that newly created subpart. Combining 

the emission standards for affected sources into a new subpart 

TTTT is appropriate because many of the same requirements, 
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including monitoring, reporting, and verification requirements, 

apply to all of the affected EGUs; and is consistent with the 

approach being taken for final existing source emission 

guidelines, in which we codify all of the requirements for the 

affected EGUs in new subpart UUUU of 40 CFR part 60.

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, integrated gasification 

combined cycle (IGCC) unit, or combustion turbine (in either 

simple cycle or combined cycle configuration) that meets the 

applicability criteria. Affected sources include EGUs 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 be (1) capable of 

combusting more than 250 MMBtu/h heat input of fossil fuel 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). 

However, we are not finalizing GHG standards for certain EGUs. 

The EGUs that are not covered by the standards we are finalizing 

in this rule include (1) non-fossil units subject to a federally 
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enforceable permit that limits the use of fossil fuels to 10 

percent or less of the heat input capacity on an annual basis; 

(2) combined heat and power units that are subject to a 

federally enforceable permit limiting annual net electric sales 

to the product of their design net efficiency times their 

potential electric output or limiting annual electric sales to 

219,000 MWh or less; (3) stationary combustion turbines that are 

subject to a federally enforceable permit limiting annual net 

electric sales to the product of their design net efficiency 

times their potential electric output or less (4) utility 

boilers and IGCC units that have always been 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; (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-fired (e.g., biomass) units

and industrial combined heat and power (CHP) units. This section 

discusses these sources and our rationale for not issuing 
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standards for them. Since the rationale applies to both steam 

generating units and combustion turbines we are describing it 

here instead of 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 to for these 

sources. 

1. Dedicated Non-fossil and Biomass Units

The proposed applicability for newly constructed EGUs 

included EGUs that primarily combust fossil fuels (e.g., coal, 

oil and natural gas). The specific applicability criteria was 

that affected units must burn fossil fuels for more than 10 

percent of total heat input on average over a 3-year average. 

Under the proposed approach, applicability with the final NSPS 

for GHG emissions could change on an annual basis depending on 

the composition of fuel burned. We solicited multiple comments 

on applicability for non-fossil units. Specifically, we 

solicited comment on a broad applicability approach that would 

include non-fossil-fired units as affected units but that would 

impose an alternate standard when the unit fires 10 percent or 

less fossil fuels of the heat input during the applicable 

determination period. We solicited comment on whether, if such a 

subcategory warranted, the applicability-determination period 
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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."

Many commenters supported an exclusion for biomass-fired 

units based on firing no more than 10 percent fossil fuels. Some 

commenters suggested that exclusion for biomass-fired units 

should be raised to a 25 percent fossil fuels threshold. 

Conversely, some commenters supported standards for biomass 

units because they are typically operated with higher heat rates 

than coal units and model results conducted by the EPA using IPM 

show that biomass generation is expected to quadruple over the 

next 10 years. These commenters said biomass units should be 

regulated consistently with coal units. One commenter supported 

the EPA's interest in ensuring that the CO2 standards issued 

pursuant to CAA section 111(d) continue to apply to existing 

EGUs when those EGUs modify or reconstruct in ways that cause 

the units to derive 10 percent or less of their heat input from 

fossil fuel because the commenter stated that allowing modified 

and reconstructed EGUs to escape 111(d) standards would 

undermine the coherence of the proposed 111(d) regulatory 

system. Some commenters supported a 3-year period for 

determining applicability; other commenters supported a 12-month 

rolling period while others supported a one-time determination.
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Some commenters stated that the standard was not developed 

to include biomass-fired units, and none of the analyses 

supporting the standard includes biomass-fired units. Commenters 

also stated that the proposed standard has not been adequately 

demonstrated as achievable by these units, and the rule offered 

no basis for regulating sources that combust insignificant 

amounts of fossil fuels. These commenters suggested that if 

biomass units must be included under these CAA section 111 

standards for fossil fuel units, they should be included in a 

separate subcategory after a subsequent proposal and comment 

period based on relevant data from biomass-fired units.

Many commenters wanted CO2 emissions from biomass (when cofired with fossil-fuels) to be excluded from applicability and 

compliance determinations. These commenters stated that the 

final national standard for CO2 emissions should encourage the 

use of biomass-fired units because this will encourage 

investments in forests which are natural sinks for atmospheric 

carbon. These commenters said that the EPA should provide a 

holistic document analyzing all issues relevant to sound policy 

for treatment of biomass units under GHG regulations after the 

Revised Framework for Assessing Biogenic CO2 Emissions from 

Stationary Sources is released and provide stakeholders 

additional time to comment. Some commenters said that biogenic 

CO2 from EGUs should be accounted for by adopting the current 
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framework for biogenic emissions under 40 CFR part 98. Other 

commenters suggested that biomass-fired units should receive 

credits toward compliance since their biogenic CO2 can be 

considered sequestered within the forest product inventories and 

markets where they procure their fuels.

The EPA has concluded that the proposed applicability based 

on the actual amount of fossil fuel burned is not a practical 

approach to define units subject to the rule. Facilities and 

permitting authorities would not know, when construction is 

commenced, whether the final NSPS is applicable, and after 

operation has commenced a unit could move in and out of 

applicability each year. The intent of this rulemaking is to 

establish GHG standards for fossil fuel-fired EGUs, not for nonfossil fuel-fired EGUs. Therefore, to clarify compliance and 

establish GHG standards for fossil fuel-fired EGUs, we have 

determined this rule will not set GHG emission standards for 

units subject to a federally enforceable permit that limits the 

use of fossil fuels to less than 10 percent of the heat input 

capacity on an annual basis. This approach allows existing 

fossil fuel-fired steam generating units to modify their 

operating permits to limit the use of fossil fuels such that the 

unit would no longer be considered fossil fuel-fired EGUs. The 

unit would not be subject to the 111(b) GHG requirements in this 

rulemaking and states would no longer be required to include 
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them in their 111(d) plan. This is consistent with the intent to 

reduce GHG emissions from fossil fuel-fired EGUs. We considered 

the fossil use restriction on both an annual and 3-year average. 

We have concluded that the single year average fossil-fuel use 

based on the annual capacity factor, and not the actual percent 

of fossil burned, provides sufficient flexibility for dedicated 

non-fossil fuel-fired units to combust fossil fuels for flame 

stabilization and other ancillary purposes. A 3-year exemption 

based on capacity factor would not cover limited use fossil fuel 

EGUs, which is not the intent of the provision.

2. Industrial Combined Heat and Power

Another approach to generating electricity is the use of 

combined heat and power (CHP) units. A CHP unit can use boiler, 

combustion turbine, reciprocating engine, and various 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 conventional power generation is recovered 

as useful thermal output. While the EPA did propose 

applicability provisions specific to CHP units (e.g., subtract 

purchased power of adjacent facilities when determining net 

electric sales), in general the proposed applicability for 

electric-only units and CHP units was similar. The intent of the 

proposed net electric sales applicability approach was to cover 
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only utility, and not industrial, CHP. To the extent the 

proposal’s applicability provisions had the effect of including 

industrial CHP, we solicited comment on an applicability 

exemption, and the criteria for that exemption, for highly 

efficient CHP facilities. We also solicited comment on 

eliminating the 219,000 MWh annual electric sales criterion for 

stationary combustion turbines based CHP. 

Many commenters supported exclusion of CHP units as a means 

of encouraging capital investments in highly efficient and 

reliable distributed generation technologies. Commenters 

recommended incorporation of 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 appropriate). 

Commenters 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. A commenter stated that the final rule 

should restrict the definition of affected facility to include 

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 5 consecutive calendar years and that CHP units 

which have total thermal energy production that approaches or 
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exceeds the unit's total electricity production should be 

exempted.

Commenters offered a number of strategies for incorporating 

an exemption for CHP units including exempting CHP units by fuel 

type and exempting industrial CHP units based on the definition 

of potential electric output. It was suggested that the percent 

sales threshold be based on the net system efficiency (that 

includes useful thermal output) rather than just the rated netelectric-output efficiency, or that the applicability criteria 

use a default efficiency of 50 percent for CHP units. Some 

commenters suggested an exclusion where CHP units would not be 

considered to be affected EGUs if 20 percent or more of their 

total gross or net energy output consists of useful thermal 

output on a 3-year rolling average basis. Some commenters said 

an exemption for highly efficient CHPs that achieve an overall 

efficiency level of 60 or 70 percent and higher should be 

excluded. Some commenters opposed removal of the sales criterion 

(219,000 MWh) because it ensures that industrial CHP are not 

subject to the standards, and the commenter believes that these 

highly efficient operations should not be encumbered by the 

regulatory burdens of the proposed standard.

In general, the inherent efficiency of CHP minimizes GHG 

emissions relative to separate generation of heat and power and 

since CHP would comply with the final GHG standards there is 
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limited environmental benefit to including CHP with significant 

environmental benefits in this GHG NSPS. In addition, the intent 

of this rulemaking is to cover utility CHP since it serves 

essentially the same purpose as an electric-only EGU, but not 

industrial CHP units since they serve a different primary 

purpose. The EPA has concluded that it is important to consider 

both purpose and efficiency when determining the scope of this 

rulemaking. The EPA, therefore, concludes that it is appropriate 

to not include in the scope of this rulemaking CHP whose primary 

purpose is providing useful thermal output and CHP with 

significant environmental benefit. To distinguish by purpose, 

the EPA concludes that SIC code classification is not a 

sufficient measure of purpose for the purposes of this 

rulemaking since it is only randomly related to the electric 

sales of a particular CHP unit.

The EPA concludes that percent of electric sales relative 

to the potential electric output is an appropriate measure of 

purpose since electric sales are inherent in the source category 

definition. The EPA considered multiple efficiency options to 

identify CHP with significant environmental benefit. We have 

concluded that overall design efficiency is not an appropriate 

method to determine environmental benefit. 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 
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thermal output). CHP units with large amounts of useful thermal 

output relative to electric output tend to have higher

efficiencies than CHP with lower amounts of relative useful 

thermal output. Therefore, an exemption based on overall 

efficiency without considering the relative amount of 

electricity to useful thermal output does not identify the 

relative GHG reductions of a CHP unit.

Based on public comments and after further analysis, the 

EPA makes two adjustments to the definition of applicability of 

this rule to CHP. The first is to base the definition of 

potential electric output on overall net efficiency, instead of 

electric-only efficiency. Second, the GHG standard applicability 

would be based on the overall design efficiency multiplied by 

the potential electric output instead of one-third of the 

potential electric output as proposed. 

We are defining utility CHP as a CHP unit that is: (1) 

technically capable of selling more electricity than the product 

of its design efficiency multiplied by its potential electric 

output and (2) not subject to a federally enforceable permit 

limiting annual net electric sales to less than this amount 

(design efficiency multiplied by potential electric output) or 

219,000 MWh, whichever is greater. The net impact of these 

changes is to only cover CHP units that condense a large portion 

of steam generated by the unit for the purpose of supplying 
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electric power to the grid. CHP facilities that do not have a 

condensing steam turbine (e.g., simple cycle combustion turbines 

with a HRSG and boiler based systems with a backpressure steam 

turbine) would generally not be physically capable of selling 

enough electricity to meet the applicability criteria – even if 

they sold 100 percent of the electricity generated and did not 

subtract out the electric used by the thermal host(s). The EPA 

has concluded that this is appropriate since these designs are 

industrial by design and provide mostly useful thermal output. 

CHP facilities with a steam extraction condensing steam turbine 

would determine their potential electric output based on their 

design efficiency on a net basis at the base load heat input 

rating. The owner/operator would be able to determine during the 

permitting process if the EGU GHG NSPS was applicable. New EGUs 

with only limited useful thermal output would be subject to the 

final standards, but the vast majority of new CHP would not be 

subject to the final standards. The EPA has concluded 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 the overall design efficiency. 

This approach both limits applicability to the intended CHP 

units and encourages the installation of the most efficient CHP 

systems since more efficient designs would be able to have 
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higher permitted electric sales while not being subject to the 

GHG 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 have not been 

typically 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. 

E. Coal Refuse

In the original proposal, we requested 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 
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a new coal refuse-fired EGU would be located in close proximity 

to the coal refuse pile, in the January 2014 proposal, we sought 

additional comments regarding a subcategory for coal refusefired EGUs. 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 said that National Emission Standards for 

Hazardous Air Pollutants (NESHAPs) and work practice standards 

which have recently been passed do enough to limit emissions 

from coal refuse plants and 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 
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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 coal refuse to be subcategorized and they 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 

unnecessary. 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 EGUs. Specifically, we are not finalizing CO2

standards for industrial CHP units. Many existing coal refusefired EGUs are CHP units. A new coal refuse-fired EGU could be 

designed as an industrial CHP facility and the requirements of 

this rule would not apply.

F. Format of the Output-Based Standard

For a non-CHP EGU, gross output is the electricity 

generation measured at the generator terminals. Net output is 

the gross electrical output less the unit’s total parasitic 

(i.e., auxiliary) power requirements. A parasitic load for an

electric generating unit is a load or device powered by 

electricity, steam, hot water, or directly by the gross output 
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of the electric generating unit that does not contribute 

electrical, mechanical, or useful thermal output. In general, 

parasitic energy demands include less than 7.5 percent of nonIGCC 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 combined cycle station 

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 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. 

However, we solicited comment on finalizing equivalent netoutput-based standards either as a compliance alternative or in 

lieu of the proposed gross-output-based standards. 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 auxiliary loads in non-CCS combined cycle designs, 

the difference between a gross-output standard and a net-output 
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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 support gross-output-based standards 

because they believe a net output standard penalizes the 

operation of air pollution control equipment. Several commenters 

disagreed with the Agency's 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 appropriate incentives to 

properly manage all of these factors. Some commenters supported 

a gross-output basis because variations in site conditions 

(e.g., available natural gas pressure, available cooling water 

sources, and elevation) will likely penalize some owners and 
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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-output-based 

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, believe that the final rule 

should strictly require compliance on a net output-basis. They 

believe this is the only way for the standards to minimize the 

carbon footprint of the electricity delivered to consumers and 

are the only standards that are truly “technology forcing.” 
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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.

The EPA recognizes that evaluating compliance on a netoutput basis more closely evaluates the environmental 

performance of the sector. However, the Agency also recognizes 

that the majority of EGU owners/operators currently use the data 

acquisition and handling technologies that have been developed 

and validated for Part 75 compliance. Currently, Part 75 only 

allows the reporting of gross energy output. In addition, many 

of the IGCC facilities are co-production facilities (i.e., they 

produce useful byproducts and chemicals along with electricity). 

As noted in the proposal, we have concluded that measuring the 

net electricity at these co-production facilities would be more 

challenging to implement.

Based on further evaluation and review of issues raised by 

commenters, for combustion turbines the EPA is finalizing the CO2

standard for 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 

currently collected under Part 75. However, many permitting 

authorities have concluded that the environmental benefits of 

using net-output-based standards outweigh any additional 
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complexities for particular units and have required them in 

recent GHG operating permits. We expect this trend to continue. 

Therefore, owners/operators of combustion turbines may petition 

the permitting authority to use the alternate net-output-based 

standard. If the permitting authority grants the petition, 

owners/operators would comply with a net-output-based standard 

that we have concluded is essentially equivalent to the grossoutput-based standard. This approach establishes a single 

applicable NSPS CO2 emission standard (i.e., units would not 

switch between the gross and net-output-based standards unless 

the Administrator grants a petition to switch) and supports the 

continued use of net-output-based standards in future GHG 

permits. 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. Finally, this approach accommodates potential 

future reporting of net output under part 75. 

In contrast, we are only finalizing gross-output-based 

standards for utility boilers and IGCC units. Providing an 

alternate net-output-based standard that is based on grossoutput-based emissions data and an assumed auxiliary load is 

most appropriate when the auxiliary load can be reasonably
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estimated and the choice between the net and gross-output-based 

standard will not impact the identified BSER. For example, for 

combustion turbines the auxiliary load is relatively fixed and 

small, approximately 2.5 percent, so the choice between the 

gross and net-output-based standard will not substantially 

impact technology choices. However, in the case of utility 

boilers, we have concluded 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 utility boilers 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., integrated solar thermal for feedwater heating 

or steam augmentation) or a coal-fired EGU co-firing natural gas 

would have lower non-CCS related auxiliary loads and since the 

required amount of CCS 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 

output-based standard.

For combined heat and power units, useful thermal output is 

also used when determining the emission rate. Previous 
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rulemakings issued by the EPA use various ‘discount factors’ 

when determining how much of the measured useful thermal output 

is 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 twothirds 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 of a hypothetical CHP unit to the proposed 

emission rate.

Many commenters said 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 

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 one hundred percent credit for 

useful thermal output for all newly constructed, modified, and 

reconstructed CHP sources. This approach approximately matches 

the overall GHG emissions from a hypothetical CHP facility to 
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separate heat and power and appropriately recognizes the 

environmental benefit of CHP.

G. CO2 Emissions Only

This final action regulates only emissions of CO2, and not 

the other constituent gases of the air pollutant GHGs. We 

identify the pollutant we are regulating as GHGs, but are only 

setting standards for CO2 emissions. We are not establishing 

separate emission limits for other GHGs (such as methane (CH4) or 

nitrous oxide (N2O)) as they represent less than 1 percent of 

total estimated GHG emissions (as CO2e) from fossil fuel-fired 

electric power generating units.

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 nonair quality health and environment 

impact and energy requirements (BSER). We noted that the D.C. 

Circuit has handed down numerous decisions that interpret this 

CAA provision, including its component elements, and we reviewed 
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that case law in detail.93

We received comments on our proposed interpretation, and in 

light of those comments, in this rule, we are clarifying our 

interpretation in certain respects. We discuss our 

interpretation below.94

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. 

 

93 79 FR 1430, 1462 (January 8, 2014).

94 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 simultaneously with this rule. Our interpretations

of these requirements in the two rules are generally consistent 

except to the extent that they reflect distinctions between new 

and existing sources. For example, as discussed below, the 

legislative history indicates that Congress intended that the 

BSER for new industrial facilities, which were expected to have 

lengthy useful lives, would include the most advanced pollution 

controls available, but Congress had a broader conception of 

BSER for existing facilities.
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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.” Section 111(b)(2). The 

term “standard of performance” is defined to “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 nonair quality health 

and environmental impact and energy requirements) the 

Administrator determines has been adequately demonstrated.” 

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.95 In addition, the D.C. 

 

95 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 
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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 2011,96 through which the Court has 

developed a body of case law that interprets the term “standard 

 

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 

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, which is 

applicable at present. 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.

96 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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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 emissions limits 

that the EPA promulgates must be “achievable” by application of 

a system of emission reduction that the EPA determines to be the 

“best system” 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”97 reduced and the role of

“technological innovation.”98

We discuss each of these elements below.

a. Achievability of the standard of 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). A standard of 

performance is “achievable” if a technology can reasonably be 

projected to be available to new sources at the time they are 

 

97 See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981). 

98 See Sierra Club v. Costle, 657 F.2d at 347.
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constructed that will allow them to meet the standard.

99

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. In sections below, we show both that for new, modified, 

and reconstructed steam generators and combustion turbines, each 

BSER that we identify is technically feasible and adequately 

demonstrated, considering cost, nonair quality health and 

environmental impact and energy requirements; and that each of 

the standards for emissions that we promulgate is achievable.

b. 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). 

c. Amount of emissions reductions. In the January 2014 proposal, 

 

99 See Portland Cement v. Ruckelshaus, 486 F. 2d 375, 391 (D.C. 

Cir. 1973).
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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 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”).100 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 reduction” is the 

“best,” EPA must consider the amount of emission reductions that 

the system would yield. Even if the EPA were not required to 

consider the amount of emission reductions, the EPA has the 

 

100 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 remains valid for the phrase “best 

system.”
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discretion to do so, on grounds that either the term “system of 

emission” or the term “best” may reasonably be read under 

Chevron step 2 to allow that discretion

d. 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,101 in 

several cases the D.C. Circuit has elaborated on this cost 

factor and formulated the cost standard in various ways, stating 

that EPA may not adopt a standard the cost of which would be 

“exorbitant,”102 “greater than the industry could bear and 

survive,”103 “excessive,”104 or “unreasonable.”105 These 

formulations appear to be synonymous, and for convenience, in 

this rulemaking, we will use reasonableness as the standard, so 

that a control technology may be considered the “best system of 

emission reduction ... adequately demonstrated” if its costs are 

reasonable, but cannot be considered the best system if its 

costs are unreasonable.106 

 

101 79 FR 1430, 1464 (January 8, 2014).

102 Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 

1999).

103 Portland Cement Ass’n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 

1975).

104 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).

105 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).

106 These cost formulations are consistent with the legislative 

history of section 111. The 1977 House Committee Report noted:
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The D.C. Circuit has never invalidated a standard of 

performance on grounds that it was too costly. 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.”

107 See Essex Chemical Corp. v. Ruckelshaus, 486 

F.2d 427, 440 (D.C. Cir. 1973);108 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 

 

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.

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.

107

 1977 House Committee Report at 184.

108 The costs for these standards were described in the 

rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 

5769 (March 21, 1972).
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plants when the ”cost of the new controls ... is 

substantial”).

109

As discussed below, the EPA may consider costs on both a 

source-specific basis and a sector-wide, regional, or nationwide 

basis.

e. Non-air health and environmental impacts. 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 

and whether it is adequately demonstrated. This requirement 

makes explicit what was implicit in the initial version of 

section 111: a system cannot be “best” if it does more harm than 

good due to cross-media environmental impacts.110 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.

 

109 Indeed, in upholding the EPA’s consideration of costs under 

other provisions requiring consideration of cost, 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).

110 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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f. 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” entails considering the amount of energy required 

to run the pollution control requirements. In this rulemaking, 

as discussed below, the EPA considered the parasitic load 

requirements of partial CCS.

g. Sector- or nationwide component of factors in determining the 

BSER. 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.111 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 

 

111 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 111.112

The Court has upheld EPA rules that 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.113

Some commenters objected that this case law did not 

excuse the EPA from justifying costs and energy 

considerations on the basis of their source-specific 

impacts, but rather, required the EPA to justify costs and 

energy considerations on both a source-specific basis and a 

sector-wide, regional, or national basis. The EPA has in 

 

112 Sierra Club v. Costle, 657 F.2d at 331 (citations omitted) 

(citing legislative history).

113 Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 Fed. 

Reg. at 33,583/3 - 33,584/1). 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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fact done so here, as discussed below.

h. 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 EPA is required to 

consider technological innovation as one of the factors in 

determining the “best system of emission reduction.”114

The Court grounded its reading in the statutory text.115 We 

added that the Court’s interpretation finds firm support as well 

in the legislative history, and116 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 

 

114 See 79 FR 1430, 1465 (January 8, 2014),Sierra Club v. Costle, 

657 F.2d at 346-47.

115 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 EPA must weigh are 

broadly defined and include within their ambit subfactors such 

as technological innovation.”).

.

116 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 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 

technology; and (iii) the development of emerging technology.117

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, and it is reasonable for the EPA to interpret 

it to authorize consideration of technological innovation in 

light of Congress’s emphasis on technological innovation.

Commenters state that the requirement to consider 

technological innovation does not authorize 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. 

i. Agency discretion. As discussed in the January 2014 proposal, 

 

117 79 FR at 1465 (citing legislative history).
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the D.C. Circuit has made clear that the EPA has broad 

discretion in determining 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,”118 and emphasized that “[t]he text gives 

the EPA broad discretion to weigh different factors in setting 

the standard.”119 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 111.120

j. Lack of requirement that standard be able to 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 

 

118 Sierra Club v. Costle, 657 F.2d at 319. 

119 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.

120 Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 

1999) (paragraphing revised for convenience).
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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 111.121

Commenters contested this assertion, arguing that a 111(b) 

standard must be achievable by all new sources. We continue to 

take the same position we took in the proposed rulemaking for 

the reasons described there. We note that as a practical matter, 

in this rulemaking, the issue of whether all new steamgenerating sources can implement partial-capture CCS is largely 

dependent on the geographic scope of sequestration sites. As 

discussed below, sequestration sites are widely available, and a 

steam-generating plant with partial CCS that is sited near an 

area with sequestration sites available can serve demand in a 

large area that may not have sequestration sites available. In 

any event, the 1,400 lb CO2/MW standard that we promulgate in 

this rule can be achieved by coal-fired power plants through cofiring natural gas in lieu of installing partial-capture CCS, 

which moots the issue of the geographic availability of CCS. 

 

121 79 FR 1430, 1466 (January 8, 2014).
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k. 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(a), 402(i), 1307 (b), and 1307(b) (adding section 

48A(g) to the 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 

demonstrated for purposes of section 111 of the Clean Air Act 

....”122 

IRC section 48A(g) contains a similar constraint concerning 

the use of technology of level of emission reduction from 

electric generating unit facilities for which a tax credit is 

allowed: 

 

122 Codified at 42 U.S.C. 15962(a). EPAct05 section 421(a) 

includes a similar constraint.
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“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 

section 402(i) and 421 (a), the EPA proposed that these 

provisions barred consideration where EPAct05 assistance 

facilities were the sole support of the BSER determination, but 

EPAct05 sources could support a BSER determination so long as 

there is additional evidence supporting the determination.123 In 

addition, the EPA viewed the prohibition as relating only to the 

technology or emissions reduction for which assistance was 

given.124 The EPA likewise interpreted IRC section 48A(g) 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 

 

123 Technical Support Document p. 6.

124 Id.
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demonstrated, but the information can corroborate an otherwise 

supported determination or otherwise provide part of the basis 

for such a determination.125 The EPA also proposed the 

interpretation that the phrase “with respect to which a credit 

is allowed under this section” refers 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.126

Some commenters supported the EPA’s proposed 

interpretation. Others challenged a reading whereby EPAct05 

facility information could comprise 99 percent of the supporting 

information for a BSER determination, but could be considered 

because the determination was not based “solely” on EPAct05 

sources. They urged a reading that the EPA could consider 

information from projects funded under the EPAct05 only if, 

without that information, the EPA could justify its chosen 

standard as the BSER – in other words, a “but for” test.127 Some 

commenters argued that the provisions simply required the EPA to 

rely only upon non-EPAct05 facilities to support a determination 

 

125 Id. p. 13.

126 Id. p. 14.

127 Comments of AFPM/API p. 46.
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that a technology or level of performance is adequately 

demonstrated.128

In this final rule, the EPA is adopting the interpretations 

of both 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.129 The EPA also notes that 

the extreme example provided in the comments (reading “solely” 

to allow EPAct05 sources to be the overwhelming basis for a 

determination that a technology or level of performance is 

adequately demonstrated) is not presented here, where the 

principal evidence that partial CCS is a demonstrated and 

feasible technology comes from sources which received no 

 

128 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.

129 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 

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).
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assistance of any type under EPAct05. This evidence satisfies

the “but for” construction urged by these commenters.

Certain commenters took the extreme position that these 

EPAct05 provisions bar consideration even of facilities’ 

existence if the facility received EPAct05 assistance.130 The 

argument is that these facilities’ experience cannot be 

considered as an example of first-of-a-kind so that later-built 

plants cannot be considered to learn at all from the EPAct05 

facilities’ experience. See Section V below. The EPA does not 

accept this argument. The EPAct05 provisions relate to whether a 

technology is demonstrated, and the level of performance 

achieved by use of technology. These provisions thus relate in 

some way to an EPAct05 source’s performance and operation. 

Merely acknowledging the evident fact of the source’s existence 

is none of these. Moreover, these same commenters referred to 

these same plants in their other comments as examples of high 

costs of CCS technology. If there is an absolute prohibition on 

considering information from EPAct05 facilities, then these 

plants’ costs to date also cannot be considered. EPA also does 

not agree that these commenters could submit comments citing 

EPAct05 facilities’ experience to support their contentions but 

that the EPA is barred from responding.

 

130 Supplemental Comments of Murray Energy (comment 9498) p. 11.
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In any case, as shown in Section V below, the EPA finds

that partial 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.

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 
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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.

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 boiler or IGCC 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 netelectric 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 
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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 annually 

depending on the proportion and the amount of electricity 

actually sold and the fossil proportion of the fuel 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 to include all utility boilers and IGCC units 

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 to 

include all utility boilers and IGCC facilities that are 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 applicability 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 
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prior to the facility 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 broader 

proposed 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 rather 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 electric sales criterion should be recast 

to be based on the permit conditions. 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 netelectric sales” (emphasis added) would create regulatory 

uncertainty and could lead to applicability confusion for both 

the regulated community and regulators. In addition, we have 

concluded that applicability based on actual operating 
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conditions (i.e., actual electric sales) is not practical since 

applicability would not be known prior to determining compliance 

and could change annually. 

Therefore, this action finalizes applicability criteria 

based on design criteria and federally enforceable permit 

restrictions included in each individual permit. Based on permit 

restrictions, if any, of net electric sales, it will be clear 

from the time of construction if a unit is subject to this rule. 

To be consistent with the applicability in subpart Da (i.e., 

‘constructed for the purpose of’), the applicability includes 

utility boilers and IGCC units unless the electric sales 

restriction has always been included in the operating permit 

(i.e., in the original and the current operating permit without 

any lapses). We have concluded that this approach is equivalent

to, but clearer than, the existing language used in subpart Da. 

In addition, without the restriction to have always been subject 

to the electric sales restriction, existing units could add 

permit restrictions on allowable electric sales to avoid 

obligation under 111(d). As described in Section III, industrial 

combined heat and power and dedicated non-fossil fuel units also 

are not included in the scope of this action. 

In this rule, we are finalizing the definition of a steam 

generating EGU as a utility boiler or IGCC unit that: (1) is

capable of combusting more than 250 MMBtu/h heat input of fossil 
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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 GHG standards 

for certain EGUs. These include: (1) steam generating units and 

IGCC facilities that are currently 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) facilities 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) 

combined heat and power facilities technically capable of 

selling more electricity than the product of their design 

efficiency times their potential electric output, that are not 

subject to a federally enforceable permit limiting annual net 

electric sales to this amount (design efficiency times potential 

electric output) or 219,000 MWh (whichever is greater) or less.

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 
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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, 

through regulations, has determined that certain types of 

changes are exempt from consideration as a modification.131

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

 

131 40 CFR 60.2, 60.14(e)
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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.132

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 

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

The EPA has determined that the BSER for newly constructed 

steam generating units is partial implementation of carbon 

capture and storage (CCS) technology to the extent of removal 

efficiency that meets a final emission limitation of 1,400 lb 

CO2/MWh-gross. The final standard of performance is less 

stringent than the proposed emission limitation of 1,100 lb 

 

132 40 CFR 60.15.
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CO2/MWh-gross. This change, as will be discussed in greater 

detail later in this preamble, is in response to public comments 

and reflects a re-examination of the potential BSER 

technologies. For a newly constructed fossil fuel-fired utility 

boiler, post-combustion carbon capture can be implemented by 

treating a slip-stream of the combustion flue gas. For a newly 

constructed IGCC unit, a pre-combustion capture system can be 

used to remove CO2 from a partially shifted (or potentially unshifted) syngas stream or, alternatively by co-firing with 

natural gas. 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 of this preamble.

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 

is the modified unit’s own best potential performance. As 

explained below, however, the final BSER determination and the 

scope of modifications to which the final standards apply differ 

in important respects from what the EPA proposed.

The EPA proposed that the 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 
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section 111(d) state plan, the EPA proposed unit-specific 

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 large modifications to affected modified steam 

generating units that are consistent with the proposed BSER 

determination for modified steam generating units. The final 

standard for that subcategory of modified sources is a unitspecific 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 
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those sources that conduct modifications resulting in a 

potential hourly increase in CO2 emissions (mass per hour) of 

less than or equal to ten percent and is withdrawing the 

proposed standards for those sources.

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 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

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.
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Table 6. Final Standards of Performance for New, Modified, and 

Reconstructed Steam Generating Units

Source Sub-category Final Standard*

lb CO2/MWh-gr

New Sources All 1,400

Modified Sources

Sources where the 

modification 

results in an 

increase in 

potential hourly 

CO2 emissions (lb 

CO2/hr) of more 

than 10 percent

Best annual 

performance (lb 

CO2/MWh-gross) 

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.

For newly constructed and reconstructed steam generating 

units and for the subcategory of modified steam generating 

sources that result in more significant 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 emissions mass per unit of useful energy output, 

specifically, in pounds per megawatt-hour (lb CO2/MWh-gr).133 The 

 

133 Note that the standards for the subcategory of more 

significant modified sources 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 is also to be in the 
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standard of performance would apply to affected sources upon the 

effective date of the final action. 

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 useful energy output (on a gross basis) over the 

rolling 12-operating-month compliance period. 

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 84-operating-month compliance period 

option that we proposed 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 

both utility boilers and IGCC units. Specifically, we have 

concluded that there are unlikely to be significant issues with 

short-term variability during initial operation, in view of both 

 

form of a gross energy output-based CO2 emission limit expressed 

in units of emissions mass per unit of useful recovered energy, 

specifically, in pounds per megawatt-hour (lb CO2/MWh-gr).
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the reduced numerical stringency of the standard, and the 

availability of compliance alternatives. The EPA notes that cofiring of natural gas can also serve as an interim technology 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. 

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, 

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-gross, issued in this action 
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and reflecting certain key changes from the proposal, 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 greenhouse gas emissions and supports technological 

innovation.

B. Partial CCS as the BSER for Newly Constructed Steam 

Generating Units

In the January 2014 proposal, we proposed that partial CCS 

technology with a percentage capture that would result in an 

emission limitation of 1,100 lb CO2/MWh-gross is the BSER for new 

fossil fuel-fired steam generating units, that is, for both 

utility boilers and IGCC units. For a new utility boiler firing 

bituminous coal, the BSER at proposal would be capture and 

storage (that is, either storage on-site or transfer to a 

qualified storage facility) of approximately 40 percent of the 

CO2 from the source. In this final action, we affirm that partial 

CCS technology represents the best system of emission reduction 

for new steam generating units, but we have determined that the 

percentage of capture that qualifies as the BSER should be 

reduced to the amount that would result in an emission 

limitation of 1,400 lb CO2/MWh-gross. For a new utility boiler 
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firing bituminous coal, the BSER would be capture and storage of 

approximately 20 percent of the CO2 from the source. The change 

from the proposed emission limitation to the final emission 

limitation reflects response to comments received on the 

proposed standards and is largely based on our assessment of 

comments received on the estimated costs to implement partial 

CCS. In the sections that follow, we explain the technical 

configurations that may be used to implement partial capture to 

meet the final standard, describe the operational flexibilities 

that partial capture 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 partial capture and 

storage in the amount that results in an emission limitation of 

1,400 lb CO2/MWh-gross best meets those criteria, including, 

among others, that partial capture and storage is technically 

feasible, provides meaningful emission reductions, can be 

implemented at a reasonable cost, and is adequately 

demonstrated. We also discuss alternative (i.e., non-CCS) 

compliance options that new source project developers can also 

use to meet the final standard of performance. We also explain 

why the emission standard of 1,400 lb CO2/MWh-gross is 

achievable.

C. Rationale for the Final Emission Standards
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1. The Proposed Standards

In the January 2014 proposal, the EPA proposed an emission 

limitation of 1,100 lb CO2/MWh-gr, which would have required a 

new steam generating unit burning bituminous coal to capture and 

store (including either storage on-site or transfer to a 

qualified storage facility) roughly 40 percent of its CO2

emissions and a new IGCC unit to capture and store roughly 25 

percent of its CO2 emissions. The EPA arrived at those proposed 

levels by examining the available CCS implementation 

configurations and concluding that this level of partial CCS 

best balances the BSER criteria and results in an achievable 

emission level. The EPA did not propose to find “full CCS” 

(i.e., more than 90 percent capture and storage) to be the BSER 

because the expected costs to implement the technology are high 

and are projected to substantially exceed the projected costs of 

other dispatchable technologies that developers are considering 

(e.g., new nuclear and biomass). See generally 79 FR at 1477-78.

2. Basis for the Final Standards

For this final action, the EPA reexamined the technology 

options available at proposal. Those are: highly efficient 

generation without CCS, partial CCS, and full (i.e., more than 

90 percent) CCS. Consistent with our determination in the 

January 2014 proposal, we remain convinced that highly efficient 

generation does not represent the best system because it does 
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not achieve emission reductions beyond the sector’s business as 

usual, when options that do achieve more emission reductions are 

available. We also do not find that full CCS is the BSER 

because, at this time, the costs are predicted to be 

significantly more than that for implementation of partial CCS

and significantly more than completing technologies such as 

nuclear-powered generation. 

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 percentage capture and final standard of 

performance of 1,400 lb CO2/MWh-gross are less stringent than at 

proposal and reflect changes that were 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 supercritical utility boiler burning bituminous coal 

can meet this final emission limitation by capturing and storing 

(including on-site storage or transfer to a qualified facility) 

approximately 20 percent of the CO2 produced from the facility. 

Most new IGCC units will be able to meet the emission limitation 

using more limited CCS (i.e., less than 10 percent). This BSER

is technically feasible, as shown by the fact that postcombustion CCS is demonstrated in full-scale operation within 

the electricity generating industry, and full-scale pre-
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combustion CCS has been demonstrated in several chemical 

industry plants with results that are reasonably transferable to 

the electricity generating sector. There are also numerous 

operating results from smaller-scale operations that are 

reasonably predictive of operation at full-scale. In addition, 

partial CCS will result in substantial emissions reductions at 

reasonable cost, is consistent with the other BSER criteria, is 

adequately demonstrated, and is consistent with emission 

standards that are achievable not only through partial CCS but 

also through alternative compliance approaches.

3. Consideration of Projects Receiving Funding Under the EPAct05

As noted in Section III.K above, the EPA’s determination of 

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

assistance from the Department of Energy (DOE), as well as 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, 
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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 

assistance standing alone is sufficient to support its BSER 

determination.

D. Post-Combustion CCS

 In this section on post-combustion CCS, we describe a 

variety of facts that support our conclusion that the technical 

feasibility is adequately demonstrated. First, we describe the 

technology of post-combustion capture, citing authoritative 

sources. We then describe EGUs that have previously utilized or 

demonstrated, or are currently utilizing, post-combustion carbon 

capture technology. Further, we identify commercial vendors that 

offer carbon capture technology and offer performance 

guarantees. In addition, we note that industry and technology 

developers have publically stated their confidence in the 

feasibility and availability of CCS technologies. 

1. Post-combustion Carbon Capture – How it Works
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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 

capture takes place after the combustion of that fuel. The 

exhaust gases from many combustion processes are often at 

atmospheric pressure and are moved through the flue gas system 

by fans, and the concentration of CO2 is somewhat dilute.134 Most 

post-combustion capture system utilize liquid solvents135 that

separate the CO2 from the flue gas. Because the flue gas is at 

atmospheric pressure and is somewhat dilute, the solvents used 

for post-combustion capture are ones that separate the CO2 using 

chemical absorption (or chemisorption). Amine-based solvents136

are the most commonly used in post-combustion capture systems. 

In a chemisorption-based separation process, the CO2 is absorbed 

by the liquid solvent and then released by heating to form a 

high purity CO2 stream. This heating is referred to as “solvent 

regeneration” and is responsible for much of the “energy 

penalty” of the capture system. Steam from the boiler (or 

 

134 The typical concentration of CO2 in the flue gas of a coalfired utility boiler is roughly around 15 volume percent.

135 A solvent is a substance (usually a liquid) that dissolves a 

solute (a chemically different liquid, solid or gas), resulting 

in a solution.

136 Amines are derivatives of ammonia (NH3) where one or more 

hydrogen atoms have been replaced by hydrocarbon groups.
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potentially from another external source) that would otherwise 

be used to generate electricity is instead used in the solvent 

regeneration process. Development of advanced solvents – those 

that are chemically stable, have high CO2 absorption capacities, 

and have low regeneration energy requirements – are an active 

area of research. Many post-combustion solvents will also 

selectively remove other acidic gases such as sulfur dioxide 

(SO2) and hydrochloric acid (HCl), which can result in 

degradation of the solvent. In those cases, the acidic gases 

will need to be scrubbed to very low levels prior to the flue 

gas entering the CO2 capture system.

Additional information on post-combustion carbon capture 

can be found in a summary technical support document.137

2. 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 

 

137 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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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 “better than 

expected.”138,139 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 

to reach full capacity. Initial indications are that the 

generation side is producing more power than estimated and the 

energy penalty (parasitic load) is much lower than expected.140

Water use at the facility is consistent with levels that were 

predicted.141 The total project costs – for the power plant and 

the carbon capture plant – was $1.467B (CAD).142 The CO2 from the 

capture system is more than 99.999 percent pure with only trace 

 

138 “[W]e are achieving better than expected” operation out of the 

plant, SaskPower's Mike Marsh said April 8 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).

139 “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/

140 Correspondence between Mike Monea (SaskPower) and Nick Hutson 

(EPA), February 20, 2015.

141 30 percent of the water used for cooling comes from the 

process itself, water in the coal is reclaimed.

142 About $1.2B USD; roughly $700M (USD) for the carbon capture 

system, which was on budget.
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levels of N2 in the product stream.143 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 will be used for 

enhanced oil recovery (EOR) operations. Any captured CO2 that is 

not used for EOR operations will be stored in nearby deep brinefilled sandstone formations. Thus the Boundary Dam Unit #3 

project is demonstrating CO2 post-combustion capture, CO2

compression and transport, CO2 injection for both EOR and 

geologic storage. 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 

does not indicate that such a system could be utilized at a much 

larger utility coal-fired boiler. However, there is nothing to 

indicate that the post-combustion 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 could be used to treat a 

 

143 “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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slipstream of a much larger supercritical utility boiler 

(approximately 500 to 600 MW) in order to meet the final 

standard of performance of 1,400 lb CO2/MWh-gross, which would 

only require partial CCS on the order of approximately 20 

percent.

A “slipstream” 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 separate streams and treated separately 

in different control equipment before being recombined to exit 

from a common stack.144 A slipstream configuration is often used 

to treat a smaller portion of the bulk flue gas stream as a way 

of testing or demonstrating a control technology or measurement 

technology. For implementation of partial post-combustion 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 portion 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 

 

144 See Figure 1A from Atmospheric Environment, 43, 3974 (2009), 

for an example of this type of configuration.
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slipstream gas – resulting in an overall capture of about 20 

percent. 

In its study on the cost and performance of a range of 

carbon capture, the DOE/NETL determined that the slipstream 

approach was the most economical for carbon capture of less than 

90 percent of the total CO2.

145 The advantages of the slipstream 

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 slipstream 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 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 

 

145 “Cost and Performance of PC and IGCC for a Range of Carbon 

Capture”, Rev 1 (2013), DOE/NETL-2011/1498. Page 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 costeffective 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 further that treating a slip-stream is the most 

economical approach).
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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. The EPA is not aware 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.146

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 CCS 

 

146 In fact, Saskatchewan’s harsh winter weather and relative 

remote location are two of the reasons given for Boundary Dam’s 

relatively high costs.
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technology, which in this case also appears to be commercially 

viable. 

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. As mentioned above, the post-combustion 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) are both 

circulating fluidized bed (CFB) coal-fired power plants with 

carbon capture equipment that is equipped with amine scrubbers 

developed by ABB/Lummus. The scrubbers were designed to process 

a slipstream 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 
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CO2 from the Shady Point Plant is also sold for use in the food 

processing industry.147

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.148

Each of these processes indicate a willingness of industry 

to utilize available post-combustion technology for capture of 

CO2 for commercial purposes. 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 Trona facility as 

compared to the solvents that are being used at Boundary Dam and 

WA Parish (Thompsons, TX).149

 

147 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.

148 IEA (2009), World Energy Outlook 2009, OECD/IEA, Paris.

149 “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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3. 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 facts 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 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 for the 

reasons discussed below, that does not disqualify them from 

being considered. 

a. Petra Nova WA Parish Project. Petra Nova, a joint venture 

between NRG and JX Nippon Oil & Gas Exploration, is constructing 

a commercial-scale post-combustion carbon capture project at 

NRG's WA 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 slipstream of 

the 610 MW WA Parish facility. This project is an indication 

that developers are confident in the technical feasibility of 

post-combustion carbon capture.

The project was originally envisioned as a 60 MW slipstream 

demonstration and received DOE CCPI funding (as provided in 

EPAct05) on that basis. The project was later expanded to the 
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larger 240 MW slipstream because of the need to capture larger 

volumes of CO2 for EOR operations. No additional DOE or other 

federal funding was obtained for the expansion from a 60 MW 

slipstream to a 240 MW slipstream.150

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 or sequester 1.6 

million tons of captured CO2 each year. The project is expected 

to be operational in 2016. 

In 2014 project materials151, 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 

 

150 Thus, even if the fact that 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 DOEassisted project. As described above, even without consideration 

of this facility at all, other information adequately 

demonstrates the technical feasibility of post-combustion CCS.

151 WA Parish CO2 Capture Project Fact Sheet; available at 

www.nrg.com/documents/business/pla-2014-petranova-waparishfactsheet.pdf (2014)
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Kansai Electric Power Co., that uses a high-performance solvent 

for CO2 absorption and desorption.152 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. As an existing source, the WA 

Parish facility will not be subject to final standards of 

performance issued in this action. However, since it will be 

capturing roughly 35 percent of the CO2 produced by the facility, 

it should meet the final emission limitation of 1,400 lb CO2/MWhgross.

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. 

 

152 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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The carbon capture system at WA Parish will utilize a 

slipstream configuration. However, the system is designed to 

capture roughly 35 percent of the CO2 from the WA Parish (90 

percent of the CO2 from the 240 MW slipstream 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 slipstream from a 

1,000 MW unit in order to meet the final standard of performance 

of 1,400 lb CO2/MWh-gross. 

Again, the experience at the WA Parish will be directly 

transferable to post-combustion capture at a new utility boiler, 

even though WA Parish is an existing source. 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 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. 

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 slipstream of 

the plant’s exhaust flue gas. In May 2011, Alstom Power 

announced the successful operation of the chilled ammonia CCS 
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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 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.153

AEP, with assistance from the DOE, had planned to expand 

the slipstream 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, and did not express doubts about 

the feasibility of the technology. 

 

153 http://www.alstom.com/press-centre/2011/5/alstom-announcessucessful-results-of-mountaineer-carbon-capture-andsequestration-ccs-project/
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AEP also prepared a Front End Engineering & Design (FEED) 

Report154, explaining in detail how its pilot-scale work could be 

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.155 See 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 

 

154 AEP Mountaineer FEED study, pp 10-11

155 Id. at 11. 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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Alabama Power’s Plant Barry. The facility, which completed the 

initial demonstration phase, 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 solvent156 for CO2 absorption and 

desorption that was jointly developed by MHI and Japanese 

utility Kansai Electric Power Co. The captured CO2 from the Plant 

Barry demonstration project was stored underground in a nearby 

deep saline geologic formation.

E. Pre-Combustion CCS

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

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 

 

156 This is the same carbon capture system that is being utilized 

at the Petra Nova project at the NRG WA Parish plant.
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turbine combined with a heat recovery steam generator and steam 

turbine). The gasification process also typically produces some 

amount of CO2

157 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.

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 

 

157 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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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.158

2. 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’s Great Plains Synfuels Plant uses 

approximately 18,000 tons of North Dakota lignite in a coal 

gasification process which produces syngas (a mixture of carbon 

monoxide, carbon dioxide, and hydrogen) which is then converted

to methane gas (synthetic natural gas) using a methanation 

process. Each day the process produces an average of 145 million 

cubic feet of synthetic natural gas that is ultimately 

transported used for home heating and electricity generation.159

 

158 Technical Support Document – “Literature Survey of Carbon 

Capture Technology”, available in the rulemaking docket (Docket 

ID: EPA-HQ-OAR-2013-0495).

159 http://www.dakotagas.com/Gasification/
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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 facility 

is not an EGU, it has significant similarities to an IGCC, and 

that 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.
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As explained above, in an IGCC gasification system, coal 

(or petroleum coke) is gasified to produce a synthesis gas 

comprised of primarily of carbon monoxide (CO), hydrogen (H2) and 

some amount of CO2 (depending on the gasifier and the specific 

operating conditions). A water-gas-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.160

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 

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 

 

160 “Cost and Performance of PC and IGCC for a Range of Carbon 

Capture”, Rev 1 (2013), DOE/NETL-2011/1498.
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present purposes, it is only the manner in which the syngas is 

used that 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.161

b. International projects. There are some international projects 

that are in various stages of development that indicate 

confidence by the developers in the technical feasibility of 

pre-combustion carbon capture. Summit Carbon Capture, LLC is 

developing the Caledonia Clean Energy Project, a proposed IGCC 

plant that would be built in Scotland, U.K. Captured CO2 from the 

 

161 www.lindeengineering.com/en/process_plants/hydrogen_and_synthesis_gas_pla

nts/gas_processing/rectisol_wash/index.html
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plant will be transported via on-shore and sub-sea pipeline to a 

subsea saline formation in the North Sea for sequestration. The 

U.K. Department of Energy & Climate Change (DECC) recently 

announced funding to allow for feasibility studies on a proposed 

570-megawatt, IGCC power plant that would include CCS.162

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.163

Vattenfall and Nuon’s pilot project in Bugennum, The 

Netherlands involves capture from a coal- and biomass-fired IGCC 

plants. It has operated since 2011.164

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 2010.165

 

162 http://www.downstreambusiness.com/item/Summit-Power-WinsFunding-Studies-Proposed-IGCC-CCS-Project_140878

163 http://sequestration.mit.edu/tools/projects/greengen.html

164 Buggenum Fact Sheet: Carbon Dioxide Capture and Storage 

Project, Carbon Capture & Sequestration Technologies @ MIT, 

http://sequestration.mit.edu/tools/projects/buggenum.html (last 

visited ).

165 Puertollano Fact Sheet: Carbon Dioxide Capture and Storage 

Project, Carbon Capture & Sequestration Technologies @ MIT, 
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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 2016.166

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.

167

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.

3. 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 

 

https://sequestration.mit.edu/tools/projects/puertollano.html

(last visited ).

166 ESI CCS Project Fact Sheet: Carbon Dioxide and Storage 

Project, Carbon Capture & Sequestration Technologies @ MIT, 

http://sequestration.mit.edu/tools/projects/esi-ccs-project

(last visited ).

167 Utmaniyah CO2 EOR Demonstration Project, Global CCS 

Institute, http://www.globalccsinstitue.com/project/uthmaniyahco2-eor-demonstration-project-0 (last visited ).
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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 

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 
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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. 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 precombustion carbon capture system to reduce CO2 emissions by 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:

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)168

 

168 Mississippi Power Company, Kemper County IGCC Certificate 

Filing, Updated Design, Description and Cost of Kemper IGCC 
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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, 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 

2015.169 The facility will utilize the Linde Rectisol® gas 

cleanup process to capture carbon dioxide – the same process 

that has been deployed for decades, including at the Dakota 

Gasification facility.170

Hydrogen Energy California, LLC (HECA), is proposing to 

build an IGCC facility similar to TCEP in western Kern County, 

 

Project, Mississippi Public Service Commission (MPSC) DOCKET NO. 

2009-UA-0014, filed December 7, 2009.

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

Houston Chronicle (April 1, 2015).

170 http://www.texascleanenergyproject.com/project/
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California. The HECA IGCC plant will be fueled by coal and

petroleum coke that will produce 300 MW of power and will 

capture CO2 for use in EOR operations. They expect to capture

approximately 90 percent of the produced CO2. HECA also intends 

to employ the Rectisol® process for carbon capture.171

Neither of these facilities has been constructed; so they 

do not provide direct evidence of technical feasibility. 

However, they both plan to employ the same carbon capture 

technology that is used at the Dakota Gasification facility and 

provide a clear indication that project developers have 

confidence in that technology.

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 

 

171 http://energy.gov/fe/hydrogen-energy-california-project
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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. 

1973), the Court (upholding standards 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)”).

172 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.”173

Linde and BASF offer performance guarantees for CCS 

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 literature174

 

172 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.”).

173 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”).

27 www.intermediates.basf.com/chemicals/web/gastreatment/en/function/conversions:/publish/content/products-and-
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they note that Linde is offering turn-key capture plants while 

BASF is the world’s leading technical supplier for gas 

treatment. According to their literature, the companies are 

making commercially available post-combustion capture technology 

for lignite and hard coal fired power plants, and are offering

“proven and tested processes including guarantees” (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 CCS. For example, Fluor has developed patented CO2

recovery technologies to help its clients reduce GHG emissions. 

The Fluor product literature175 specifically points to Econamine 

FG PlusSM process which uses an amine solvent to capture and 

produce food grade CO2 from post-combustion sources. The

literature further notes that Econamine FG PlusSM (EFG+) is also 

used for carbon capture and sequestration projects, that 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 

 

industries/gas-treatment/images/Linde_and_BASFFlue_Gas_Carbon_Capture_Plants.pdf.

175 www.fluor.com/client-markets/energy-chemicals/Pages/carboncapture.aspx
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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.176 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 

greenhouse gas 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. 

In addition, Shell has developed the CANSOLV CO2 Capture 

System, which Shell describes in its product literature177 as a 

world leading amine based CO2 capture technology that is ideal 

for use in fossil fuel-fired power plants where enormous amounts 

 

176 http://www.powermag.com/commercially-available-co2-capturetechnology/

177 www.shell.com/global/products-services/solutions-forbusinesses/globalsolutions/shell-cansolv/shell-cansolvsolutions/co2-capture.html
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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 greenhouse gas abatement 

regulations by removing CO2 from their exhaust streams, with the 

added benefit of simultaneously lowering SO2 and NO2 emissions.

Other companies are at various stages of developing and 

demonstrating processes to remove CO2 from flue gas streams.

2. Academic and Other Literature 

Climate science and climate change mitigation options – include 

CCS - are the subject of great academic interest and a large 

body of academic literature on the subjects exits. In addition, 

other research organizations (e.g., U.S. national laboratories 

and others) have also published studies on these subjects. A 

compendium of relevant literature is provided in a Technical 

Support Document available in the rulemaking docket.178 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 

 

178 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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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 the fact the SelexolTM process has been used in 

industry for decades minimized technical risk of its use at the 

Kemper IGCC facility. 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.179

And ... 

“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.”180

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 

 

179 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).

180 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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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.”181

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).182

As discussed above, in fact, vendors do offer performance 

guarantees. Moreover, as noted above, Boundary Dam Unit #3 is a 

full-scale project that is successfully implementing full CCS 

with post-combustion capture, and Dakota 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 

 

181 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.

182 Alstom Comments, p. 3.
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expressed confidence in the availability and performance of CCS 

technology.

183

G. Response to Key Comments

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 Court has explained that a standard of performance 

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. (See 79 FR 1463; see 

also Section V.C above.) However, as discussed above, CCS 

technology is available through vendors who provide performance 

guarantees, which indicates that in fact, CCS is commercially 

 

183 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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available, which adds to the evidence that the technology is 

adequately demonstrated to be technically feasible.

2. Must a technology be in full-scale 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 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 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.

184 In any event, as 

 

184 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.9-

1196, 91st Cong., 2d Sess. 16 (1970).
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discussed above, Boundary Dam has provided data from the 

operation of the CCS equipment itself.

In a related argument, other commenters stated that a 

system cannot be adequately demonstrated unless all of its 

component parts are operating together.185 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).

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).

 

185 See e.g. Comments of UARG p. 5.
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3. Scalability of Pilot and Demonstration Projects

Commenters maintained that 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, 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.186 The EPA 

has done so here. 

Most obviously, the final standard reflects experience 

of full-scale operation of both pre- and post-combustion 

carbon capture. 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 full-scale for both utility boiler and IGCC 

facilities. See, for example, the detailed description of 

 

186 Sierra Club v. Costle, 657 F. 2d 298, 341 n.157 and 380-84 

(D.C. Cir. 1981). See also 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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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 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.187 The DOE/NETL is explicit that its studies 

confirm the technical feasibility of CCS, stating, in 

relevant part, that the “studies ... establish estimates for 

the cost and performance of combustion and gasification 

based power plants ... with ... carbon dioxide capture and 

storage. Several ranks of coal are being assessed in 

process configurations that are based on technology that 

could be constructed today such that the plant could be 

operational in the 2012 - 2015 timeframe.”188

It is important to note that, while some commenters 

challenged EPA’s use of costs in the DOE/NETL cost and 

performance reports, commenters did not challenge the technical 

methodology in the work.

 

187 See NETL pp. 57-74.

188 http://www.netl.doe.gov/research/energy-analysis/energybaseline-studies
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In addition, the AEP FEED study indicates how the 

development scale post-combustion CCS could be successfully 

scaled up to full scale operation. See above.

Much has been written about the complexities of adding CCS 

systems to fossil fuel-fired power plants. Some commenters 

argued that the EPA minimized – or even ignored - those 

complexities in the discussion presented in the January 2014 

proposal. On the contrary, the EPA has not minimized or ignored

these complexities. 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.”189 This statement – and most of the statements in 

this vein – are in reference to implementation of full CCS 

systems that capture more than 90 percent of the CO2. 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 cost. Concerns regarding “operating 

issues” are also often associated with implementation of full 

CCS – and often with implementation of full CCS as a retrofit to 

 

189 Report of the Interagency Task Force on Carbon Capture and 

Storage (August 2010), page 28.
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an existing source. The EPA addresses technical feasibility of 

partial CCS in this final action. The Boundary Dam facility, in 

particular, demonstrates that the complexities of implementing 

CCS – even full CCS – can be overcome. Many of the challenges 

that are often noted are only issues for implementation of CCS 

retrofits for existing sources. 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 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 EPA’s determination of 

that partial CCS is technically feasible and adequately 
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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 preamble, the EPA and others 

predict that very few 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, 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”) and 341 n. 157. 

H. Consideration of Costs
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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, EPA concludes that the costs 

associated with the final standard are reasonable.

In reaching this determination, the EPA evaluated capital 

costs on a per-plant basis, responding to public comment that 

noted the particular significance of capital costs for fossil 

steam EGUs. As in the proposal, the EPA also considered how the 

standard would affect the levelized cost of electricity for 

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 

cost impacts on consumers. Accordingly, EPA concludes that the 

costs of the final standard are reasonable.

1. Rationale at Proposal

At proposal, the EPA evaluated the costs of new fossil 

steam EGUs implementing full (90 percent) and partial CCS. The 
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EPA compared the predicted levelized cost of electricity (LCOE) 

of those units against the LCOE of other new units using 

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 full CCS was higher than those of these 

other technologies, and we did not propose to identify full CCS 

as BSER on this basis. Id. at 1477. The EPA determined that the 

proposed standard of performance of 1,100 lb CO2/MWh-gross, 

reflecting partial CCS, could be implemented at reasonable cost

based on a comparison of the projected LCOE associated with 

achieving this standard with the alternative dispatchable 

technologies just mentioned. 

In addition, the EPA concluded that the costs of 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 enhanced oil recovery. 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 
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type of CCS, are significantly more expensive than new naturalgas fired electricity generation, but that some electricity 

suppliers might include fossil steam generation 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 

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 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. 

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 Market Context

The EIA projects that few new fossil steam EGUs will be 

constructed over the coming decade and that those that are built 
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will apply CCS, reflecting the broad consensus of government, 

academic, and industry forecasters.

190 The primary reasons for 

this projected trend include low electricity demand growth, 

highly competitive natural gas prices, and increases in the 

supply of renewable energy. In particular, US electricity demand 

growth has followed a downward sloping trend for decades with 

future growth expected to remain very low.191 Furthermore, the

EPA projects that for any new fossil fuel-fired electricity 

generating capacity that is constructed through 2020, natural 

gas will be the overwhelming fuel of choice.

Accordingly, construction of new uncontrolled fossil steam 

generating capacity is not anticipated in the near term, even in 

the absence of the standards of performance we are finalizing 

today, 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.” 

Public announcements and IRPs also indicate that utilities are 

interested in a range of technologies that could provide or 

 

190 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.

191 EIA, “Annual Energy Outlook 2014,” Figure MT-29, May 7, 2014.
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preserve fuel diversity within generating fleets. In particular, 

fuel diversity could provide important additional value by

serving as a hedge against the possibility that future natural 

gas prices will far exceed projected levels. 

In addition, the EPA recognizes that there may be interest 

in combined-purpose plants that would generate power as well as 

produce chemicals or carbon dioxide for use in enhanced oil 

recovery projects. These facilities would similarly provide 

additional value due to the revenue streams from saleable 

chemical products or carbon dioxide.

As demonstrated below, the agency carefully considered the 

reasonableness of costs in identifying a standard that allows a 

path forward for such projects while rejecting more stringent 

options that would impose excessive costs. 

4. Consideration of Capital Costs

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.

192

Extensive comment from industry representatives and others noted

 

192 Draft RIA p. 5-20 and Table 5-5.
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that fossil-steam units are very capital-intensive projects and 

recommended that capital costs be considered 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 in 

line with prior regulations and industry experience, and because 

the fossil steam electric power industry has been shown to be 

able 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 electric generating units 

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 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. 
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In reviewing the 1979 NSPS for fossil steam electric 

generating units, 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 EPA’s 

determination that the standard was reasonable. Id. at 410.

The cost and investment impacts of the 1978 NSPS on 

electric utilities was subsequently evaluated in a 1982 

Congressional Budget Office (CBO) retrospective study.

193 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.194 The study further noted 

that air pollution control requirements in general had led to an 

estimated a 37.5 to 45 percent increase in capital costs for 

coal-fired power plant installation between 1971 and 1980.

195

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 

 

193 Congressional Budget Office, The Clean Air Act, the Electric 

Utilities, and the Coal Market, April 1982, p. 10-11, 23.

194 Id. at 10-11.

195 Id. at 22.
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better and no worse than all electric utilities in general.”196

In assessing the capital cost impacts of the suite of 1970’s 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.”197

In NSPS standards for other sectors, the EPA's 

determination that capital cost increases were reasonable has 

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 similar in magnitude on an individual unit basis 

to those projected for the present standard. We predict that the 

 

196 Id. at xvi.

197 Id.
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incremental costs of control for a new SCPC unit to meet the 

final emission limitation of 1,400 lb CO2/MWh-gross would be an 

increase of 17.3 percent for capital costs. Incremental capital 

costs of control for a new IGCC unit would be even less. See 

Table 7 below.198 

Table 7. Comparison of capital costs for a new SCPC and a new 

SCPC meeting the final standard of performance.

Total

Overnight

Capital

Cost

($/kW)

SCPC - no CCS 2,452

SCPC - partial CCS 2,876

(1,400 lb CO2/MWh-gr)

Incremental cost increase 17.3%

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. Levelized costs are often used to compare the cost of 

different potential generating sources. While capital cost is a 

 

198 We explain below the reasonableness of EPA’s cost projections 

here.
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useful and relevant metric for capital-heavy fossil-steam units, 

the LCOE can serve as a useful complement because it takes into 

account all specified costs, over the whole lifetime of the 

project. 

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 that 

for comparable alternative 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 megawatthour (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. The relative contribution of each of these inputs to 

LCOE will vary among the generating technologies. For example, 
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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. Therefore, isolating a comparison of technologies based on 

their costs is only appropriate when they can be assumed to 

provide the similar service by essentially providing the similar 

values of electricity generated. It should be noted that 

different types of generation do not provide identical services, 

but nevertheless may be similar enough to permit of comparison 

through use of the LCOE.

As we indicated in the proposal, we evaluated publicly 

available Integrated Resource Plans (IRPs) and other available 

information (such as public announcements) to determine the 

types of technologies that utilities are considering as options 
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for new generating capacity.199 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. The options for dispatchable 

generation 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 easily ramped 

up or down as needed, e.g., coal-fired units, NGCC units, 

 

199 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.
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nuclear) with that of non-dispatchable technologies generating 

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 other sources, 

as shown in Table 8 below. As discussed in further detail below, 

these estimates rely most heavily on DOE/NETL cost projections 

for fossil fuel generating technologies and on the updated 

DOE/EIA AEO2014 for non-fossil generation technologies.

Table 8. Predicted Cost and CO2 Emission Levels for a Range of 

Potential New Generation Technologies

New Generation Emission LCOE (+30%)

Technology lb CO2/MWh-g $/MWh

SCPC - no CCS 1,700 77 - 100

SCPC* - no CCS 1,700 89 - 116

SCPC + partial CCS 1,400 93 - 121

SCPC + partial CCS 1,100 110 – 143

IGCC - no CCS 1,450 94 – 122

IGCC + partial CCS 1,400 97 - 126

IGCC + partial CCS 1,100 109 – 142

NGCC < 1,000 52 – 86**

Nuclear 0 96 – 125
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Biomass - 103 – 134200

Geothermal 0 48 – 62

* Includes the 3 percent CUA

** This range represents a natural gas price from $5/MMBtu to 

$10/MMBtu.

As shown in Table 8 above, we project that the LCOE for new 

fossil steam capacity meeting the final 1,400 lb CO2/MWh-gross

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 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 base load generation diversity – or at least non-NGCC 

alternatives -- to a power provider’s portfolio; hence, they are 

viewed as comparable alternatives.

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 

 

200 Table 8 includes LCOE figures for geothermal and biomassfired generation, other potential sources of dispatchable base 

load power that are not fueled by natural gas. The EPA includes 

this information for completeness, while noting that both 

options have limitations such that they are not as robust 

analogues as nuclear power. Geothermal generation is 

geographically limited and biomass-fired units in operation in 

the U.S. are smaller scale.
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price. However, public IRPs indicate 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. 

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 – base load power and fuel 

diversity. 

We note further 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, do not reflect revenues 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 

co-firing with natural gas.
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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 “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-XX-YYY, June 2015) (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 

are built would have CCS.201 Instead, EIA data shows that natural 

 

201 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 
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gas is likely to be the most widely-used fossil fuel for new 

construction of electric generating capacity through 2020. Of 

the coal-fired units moving forward at various advanced stages 

of construction and development - Southern Company's Kemper 

County Energy Facility, Summit Power's Texas Clean Energy 

Project (TCEP), and the Hydrogen Energy California Project 

(HECA) – each will deploy IGCC with some level of CCS.202 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 2022.203 More broadly, this regulation is not expected to have 

 

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.

202

These sources received federal assistance under EPAct 2005. 

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.

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

model year of 2020.
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significant effects on fuel markets, electricity prices, or the 

economy as a whole, as described in detail in Chapter [x] 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 today 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 incremental cost of tens 
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of billions of dollars.204 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 (as we did at proposal). 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.”205 These facts support 

EPA’s overall conclusion that the costs of the standard are 

reasonable. 

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 

 

204 Sierra Club, 657 F 2d at 314

205 Portland Cement Ass’n, 513 F. 2d at 508.
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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 or IGCC unit 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.

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 captured CO2 for EOR. The Kemper facility likewise 

plans to do so.206

 

206 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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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 

conservative assumptions embodied in our assessment of 

compliance costs. 

c. 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-gross is the BSER for newly constructed fossil 
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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-gr 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.

Most new IGCC units will be able to meet the final standard 

by capturing less than 10 percent of the CO2 and many IGCC

designs have a sufficient compliance margin such that they would 

likely not need to use a water-gas-shift (WGS) reactor. As an 

alternative, most new IGCC facilities will be able to meet the 

final standard by co-firing less than ten percent natural gas.

Natural gas co-firing has long been recognized as an option 

for coal-fired boilers to reduce emissions of criteria and 

hazardous air pollutants. The EPRI sponsored a study to assess 

gas co-firing in coal-fired boilers207 where they examined both 

technical and economic issues associated with natural gas cofiring. They determined that the largest number of applications 

and the longest experience time is with natural gas reburning 

 

207 Gas Cofiring Assessment for Coal Fired Utility Boilers; Final 

Report, August 2000; EPRI Technical Report available at 

www.epri.com.
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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 fuel-rich 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 utilize natural gas.208,209

A 2013 article entitled “Utility Options for Leveraging 

Natural Gas”210 noted that: 

 

208 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. 

209 “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. 

210 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. 

Table 9. Predicted Costs to Meet the Final Standard Using 

Natural Gas Co-firing.

New Generation Emission LCOE* (+30%)

Technology lb CO2/MWh-g $/MWh $/MWh

SCPC - no CCS 1,700 77 100

SCPC + partial CCS 1,400 93 121

SCPC + NG co-fire 1,400 90 -

IGCC - no CCS 1,450 94 122

IGCC + partial CCS 1,400 97 126

IGCC + NG co-fire 1,400 95 -

NGCC < 1,000 59 – 86 -

* The LCOE values for non-natural gas generation (i.e., SCPC 

with and without CCS) include +30% for uncertainty. The NG 

technologies (i.e., co-firing and NGCC) are costs assuming a 

range of natural gas prices from $6.11/mmBtu to $10.00/mmBtu.

The EPA thus again notes that the cost assumptions it is 

making here are highly conservative. That is, by costing partial 

CCS as BSER, the EPA is likely overestimating actual compliance 
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costs since there exist other less expensive means of meeting 

the promulgated standard.211

d. 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 

 

211 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.
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County IGCC facility. The operators of the Boundary Dam Unit #3 

are considering construction of additional CCS units and 

projected that the next units could be constructed at a cost of 

at least 30 percent less than that at Unit #3. 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.212 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).213 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 expect continued additional cost reductions to come from 

knowledge gained from continued operation of non-power sector 

 

212 http://www.saskpowerccs.com/consortium/

213 http://www.saskpowerccs.com/ccs-projects/shand-carbon-capturetest-facility/
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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.

e. 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 

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 
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intend to use captured CO2 to improve recovery of oil in mature

fields.214

I. Key Comments Regarding EPA’s Consideration of Costs

1. Use of LCOE as a Cost Metric

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.215 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 

 

214 Tracking Clean Energy Progress 2013, International Energy 

Agency (IEA), Input to the Clean Energy Ministerial, OECD/IEA 

2013.

215 Comments of EEI, pp 94-5.
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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 

associated with CCS. The EPA disagrees with this contention. The 

LCOE does not mask consideration of capital costs. Rather, as 

explained above, it addresses all costs equally and therefore 

provides a useful summary metric of all sources of costs per 

unit of production (i.e., megawatt-hours). Provided that those 

megawatt-hours are equally valuable, 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 accordingly as 

discussed above, the EPA has considered direct capital costs 

here as part of its assessment and found those costs to be 

reasonable. At the same time, the agency believes LCOE is a 

valuable complementary metric because there are other costs that 

are also considered when evaluating technology options to 

provide new generating capacity. According to EIA216, the capital 

costs represent roughly 63 percent of the LCOE for a new coalfired SCPC plant; roughly 66 percent of the LCOE for a new IGCC 

plant; roughly 74 percent of the LCOE for a new nuclear plant; 

 

216 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm
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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, for a variety of 

reasons, the power sector has moved toward increased use of 

natural gas. 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, the EPA 

recognizes the variety of factors that can be involved in 

selecting a generation source beyond capital costs, and in 

considering cost reasonableness we accordingly also 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 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, both new nuclear power 

and fossil steam generation are similarly not competitive with 

new natural gas if evaluated on the basis of LCOE alone. 
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Nonetheless, both are important potential alternatives to 

natural gas power for those interested in dispatchable base load

power that maintains or increases fuel diversity. Because both 

fossil steam and nuclear generation serve a comparable role of 

offering a diverse source of base load power generation, EPA 

concludes that the comparison of their LCOE is a valid approach 

to evaluating cost reasonableness.

Finally, the EPA noted that new nuclear addresses potential 

risks (including future costs to the source) associated with 

future carbon liabilities – the same risks coal with some degree 

of CCS would address. See 79 FR at 1477.

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 AEO2013 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 AEO2014 for nuclear and other baseload nonfossil generation technologies.

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 
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and performance of combustion and gasification based power 

plants with and without CO2 capture and storage.217 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.218 The NETL studies 

were extensively peer reviewed.219 The EPA Science Advisory Board 

Work Group considering the adequacy of the peer review noted EPA 

staff’s statement that “the NETL studies were all peer reviewed 

under DOE peer review protocols”, further noted EPA staff’s 

statement that “the different levels of review of these DOE 

documents met the requirements to support the analyses as 

defined by the EPA Peer Review Handbook,” and concluded that 

 

217 http://www.netl.doe.gov/research/energy-analysis/energybaseline-studies

218 The NETL costs and studies are often cited in academic and 

other publications.

219 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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“peer review on the DOE documents” was conducted “at a level 

required (sic) by agency guidance.”220

The cost estimates were indicated by DOE/NETL to carry an 

accuracy of -15 percent to +30 percent, consistent with a AACE 

Class 4 cost estimate – i.e, a “feasibility study” level of 

design engineering.221 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.”

222

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 

 

220 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

221 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.

222 “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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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 

Electric Power Research Institute (EPRI)223, by the DOE’s Energy 

Information Administration (EIA) in their 2014 Annual Energy 

Outlook (AEO2014), 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. 

 

223 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).
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Table 10. Selection of Levelized Cost of Electricity (LCOE) Projections 

EPA Proposal224 EPRI225 AEO2014226 DOE/NETL227 CMU228

$2011/MWh $2011/MWh $2012/MWh $2011/MWh $2010/MWh

SCPC 92* 62 -77 87 - 114* 91 - 118 59

SCPC(full CCS) 147 102 – 137 - 147 - 191 -

SCPC(partial CCS**) 110 - - 110 - 126 80

IGCC 97 82 – 96 106 - 132* 101 - 131 -

IGCC(full CCS) 136 105 – 136 137 - 163 142 - 185 -

IGCC(partial CCS**) 109 - - 112 - 146 -

NGCC 59 - 86 33 – 65 59 - 86 60 - 77 63

Nuclear 103 - 114 85 – 97 93 - 102 - -

Geothermal 80 - 99 84 - 129 46 - 50 - -

Biomass 97 - 130 90 - 155 92 - 123 - -

* These cost projections include a climate uncertainty adder (CUA); which is a 3-

percentage point increase in the cost of capital

** Partial CCS is 1,100 lb/MWh for EPA costs; 1,000 lb/MWh for CMU cost

 

224 79 FR 1430; Tables 6 and 7; Partial CCC is an emission limitation of 1,100 lb CO2/MWh.

225 "Program on Technology Innovation: Integrated Generation Technology Options 2012; 

Report 1026656; Available at:www.epri.com

226 “Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual 

Energy Outlook 2014”, Available at: www.eia.gov/forecasts/aeo/electricity_generation.cfm

227 Recommendation by NETL for next-of-a-kind cost projections. Available in the rulemaking 

docket at EPA-HQ-OAR-2013-0495-0065. Range includes +30 percent uncertainty.

228 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; Note: the 

authors assumed an emission limit of 1,000 lb CO2/MWh
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The LCOE values from the EPRI, EIA, 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 + 30 percent uncertainty 

added as the higher estimate in the range. 

The range presented for the EIA AEO2014 LCOE values is 

intended to represent regional variation for new generating 

sources (reflecting regional differences in construction labor 

costs, capital costs, and resource availability). Overall, as 

can be seen from the results in Table 10, the range of LCOE 

estimates from the different groups are in reasonable agreement.

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 GHGintensive projects in a context of climate uncertainty. The EPA 
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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 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 and includes the CUA in the cost of 

coal-fired utility boilers when evaluating competitiveness of 

that generating technology.

c. Industry information that corroborates NETL cost estimates. 

Information from vendors of CCS technology also supports the 

reliability of the cost estimates EPA is using here.229 

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 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 

 

229 See 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.
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of the captured CO2 for EOR.230 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 

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.231 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 

 

230 http://www.summitpower.com/projects/carbon-capture/

231 “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 (ID: EPA-HQ-OAR-2013-0495).
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predictions.232 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 

with costs in those 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.”

In June 2012, Alstom Power released a report entitled “Cost 

assessment of fossil power plants equipped with CCS under 

typical scenarios”.233, 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 the 

Summit – are shown in Table 11 below. The EPA estimated costs 

 

232 No proprietary or business confidential information was shared 

with EPA. No specific vendors were mentioned by name during 

discussions with Summit Power. Summit also used available 

DOE/NETL and EIA cost information.

233 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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are also included for comparison. The results show predicted 

costs for a new SCPC ranging from $53/MWh to $81/MWh and costs 

to implement full CCS ranging from $97/MWh to $147/MWh. Costs to 

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. There is very good 

agreement among the studies in the incremental cost to implement 

full CCS on the new SCPC units (ranging from 82 to 85 percent).

Table 11. Industry LCOE Estimates for Implementation of PostCombustion CCS

Summit Alstom EPA

$/MWh $/MWh* $/MWh

SCPC 64.5 52.6 81.0

SCPC + full CCS 117.6 97.4 147.0

Full CCS incremental cost, % 82.3% 85.0% 81.5%

SCPC + 50% CCS 91.1 - -

SCPC + 40% CCS - - 110.0

SCPC + 20% CCS - - 97.0

NGCC** 47.7 35.0 59.0

* 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).

** Assumed natural gas prices = Summit ($4/mmBtu); Astom 

($3.9/mmBtu); EPA ($6.11).

The EPA notes that in its public comments, Alstom maintained 

that “no CCS projects that would [sic] be considered cost 
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competitive in today’s energy economy.”234 As explained above, no 

steam electric EGU would be cost competitive even without CCS –

and that is substantiated in the projected costs present above 

in Table 11 where NGCC is consistently the most economic new 

generation option when compared the other listed technologies. 

Alstom does not explain (or address) why the cost premium for 

partial CCS would be a decisive deterrent for capacity that 

would otherwise be constructed. More important, Alstom does not 

challenge the specific cost estimates used by the EPA at 

proposal (and in this final rule), nor disavow its own estimates 

of CCS costs (which are even less) which it is publically 

disseminating in the marketplace. See also above, quoting 

Alstom’s press release stating unequivocally that “CCS works and 

is cost-effective”. 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 

AEO2013 cost projections for non-fossil based generation. The 

 

234 Alstom Comment p. 3. The comment also urged 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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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 AEO2013. Those costs were updated as part of 

the AEO2014 release. The changes are shown below in Table 12 

below.

Table 12. Predicted Cost and Regional Variation (Range) for New 

Non-fossil Dispatchable Generating Technologies

AEO2013 AEO2013 AEO2014 AEO2014

average range* average range*

Technology $2011/MWh $2011/MWh $2012/MWh $2012/MWh

Nuclear 108 104-115 96 93-102

Nuclear 

(w/subsidy) - - 86 83-92

Biomass 111 98-131 103 92-123

Geothermal 90 81-100 48 46-50

* Note that the “range” is intended to account for the 

significant regional variation in LCOE values based on local 

labor markets and the cost and availability of fuel or energy 

resources.

The estimated cost for all of these technologies decreased 

from AEO2013 to AEO2014. This was due to changes in the 

macroeconomic projections that resulted in lower financing costs 
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in AEO2014 relative to the AEO2013. The EIA did not make any 

major updates to the initial cost inputs for most technologies, 

including nuclear.

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 

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 
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technical and economic assumptions. This consistency of approach 

allows meaningful comparisons among the cases evaluated.”

The EIA AEO2014 presented LCOE costs as a single point 

estimate representing average nationwide costs and separately as 

a range to represent the regional variation in costs. That range 

reflecting regional variation is presented in Table 12. In order 

to compare the fossil fuel generation technologies from the NETL 

studies with the cost projections for non-fossil dispatchable 

technologies from EIA AEO2014, we assume that the EIA studies 

would carry a similar level of uncertainty (i.e., +30 percent) 

and we present the AEO2014 projected costs as the average 

nationwide LCOE plus an additional 30 percent to account for 

uncertainty.

3. Use of Costs from Current Projects

Although we are relying on cost estimates drawn from technoeconomic 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-todate) 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 
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why the EPA considers that the next new plants will have lower 

costs along the lines predicted by NETL.235

The Boundary Dam Unit #3 facility utilizing post-combustion 

capture from Shell Cansolv is now operational. Petra Nova, a 

joint venture between NRG 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 postcombustion capture system will utilize MHI amine-based solvents 

and is currently being constructed with plans to initiate 

operation in 2016.236

Construction on Mississippi Power’s Kemper County Energy 

Center IGCC facility is now nearly complete. The combined cycle 

 

235 The EPA notes that two of these facilities, Kemper and HECA, 

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. 

236 http://www.nrg.com/sustainability/strategy/enhancegeneration/carbon-capture/wa-parish-ccs-project/
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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 2016.237

Other full-scale projects – such as the Summit Power Texas 

Clean Energy Project and the Hydrogen Energy California Project 

– have not commenced construction but remain viable projects. 

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. 

Many commenters felt that the EPA should rely on those high 

costs when considering whether the costs are reasonable.238 The 

costs from these large-scale projects appear to be consistently 

higher than those projected by techno-economic models. However, 

 

237 http://www.mississippipower.com/about-energy/plants/kempercounty-energy-facility/facts

238 At other times some of the same commenters insisted that the 

EPA is forbidden from considering the costs from any projects

that received funding from the Energy Policy Act of 2005.
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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, the report “reflect[s] the 

cost of the next commercial offering for plants that include 

technologies that are not yet fully mature and/or which have not 

yet been serially deployed in a commercial context, e.g. IGCC 

plants and any plant with CO2 capture. These cost estimates for 

next commercial offerings do not include the unique cost 

premiums associated with first-of-a-kind (FOAK) plants that must 
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demonstrate emerging technologies and resolve the cost and 

performance challenges associated with initial iterations.”239

 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.

 Research is underway 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 largescale 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 solvents, such as amines, to separate CO2 from other 

gases have been in use since the 1930s in the natural gas 

 

239 NETL p. 37.
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industry and to produce food and chemical grade CO2. The 

advancement of amine-based 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.

To facilitate the transfer of the technology and to 

accelerate development of carbon capture technology, SaskPower 

has created the CCS Global Consortium.240 This consortium 

provides SaskPower the opportunity to share its knowledge and 

experience with global energy leaders, technology developers, 

 

240 http://www.saskpowerccs.com/consortium/
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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).241 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 suggests that their costs are uniquely high, 

and otherwise not fairly comparable to the costs of plants 

meeting the NSPS using the BSER. Most obviously, all of these 

projects involve full rather than partial CCS.

In addition, we note that the Administration’s CCS Task 

Force report recognized that CCS would not become more widely 

available without the advent of a regulatory framework that 

promoted CCS or a provided a strong price signal for CO2. Today’s 

action is an important component in developing that framework.

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 

 

241 http://www.saskpowerccs.com/ccs-projects/shand-carbon-capturetest-facility/
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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, 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 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

Commenters, however, argued that this conclusion – that 

without a CCS-based NSPS, no coal-fired generation will be 

built. They contented 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. There have been very few new 

coal-fired generating sources built 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 
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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 coal-fired 

power plants in the near future – even in the absence of these 

final standards.

5. Accuracy of Cost Estimates for Transportation and 

Geologic Sequestration

The EPA’s estimates of costs include 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 also consistent with 

other published studies.

242 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 

 

242 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) and 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.
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Greenhouse Gas Reporting Program subpart RR for geologic 

sequestration of CO2 in deep saline formations.243

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.

244 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.

245 Some 

commenters suggested that the EPA underestimated the costs 

associated with transporting captured CO2 from an EGU to a 

sequestration site.246 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. 

 

243 Carbon Dioxide and Transport and Storage Costs in NETL 

Studies. DOE/NETL-2013/1614. March 2013. P. 13.

244 RIA at ; proposed rule RIA at 5-30.

245 http://www.globalccsinstitute.com/publications/economicassessment-carbon-capture-and-storagetechnologies-2011-update.

246 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

included 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 estimated transport, storage and 

monitoring (TSM) costs of $5-$15 per ton of CO2 for non-EOR 

applications.247 This estimate is reflected in the LCOE 

comparative costs.248

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.

249 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.250 For new sources, pipeline distance and 

 

247 See RIA at and proposed rule RIA at 5-30. For EOR 

applications the point of sale is typically the facility fence 

line, in which case the CO2 supplier (i.e. the EGU) will avoid 

the TSM cost. Consequently, the economic benefit of EOR may be 

greater than simply the price paid for CO2.

248 See RIA at .

249 The pipeline diameter was sized for this to be achieved 

without the need for recompression stages along the pipeline 

length. 

250 JJ Dooley, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH Kim, 

EL Malone (2006), Carbon Dioxide Capture and Geologic Storage: A
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costs can be factored into siting and, as discussed in section 

V.K, there is widespread availability of geologic formations for 

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.K 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 Greenhouse 

Gas Reporting Program 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 project was 

not full scale, finding a suitable repository, notwithstanding 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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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.

251

The EPA’s cost estimates account for the requirements of 

the Underground Injection Control Class VI program, and 

Greenhouse Gas Reporting Program 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.

252 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 for transporting 

and injecting CO2.

253,254 Monitoring costs were evaluated based on 

 

251 AEP Comments at pp. 93, 96. 

252 NETL 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.

253 Bock, B., R. Rhudy, H. Herzog, M. Klett, J. Davidson, D G. De 

La Torre Ugarte, and D. Simbeck. (2003). Economic Evaluation of 
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the methodology set forth in the International Energy Agency 

Greenhouse Gas R&D Programme’s Overview of Monitoring Projects 

for Geologic Storage Projects report.255

The EPA’s cost estimates for sequestration thus cover all

aspects commenters claimed the EPA disregarded. The EPA also 

made reasonable assumptions regarding the assumed injection 

site: a deep saline formation with typical characteristics 

(e.g., depth and pressure).256 To that end, the EPA believes that 

the use of the costs and scenarios presented in these studies 

referenced are representative for the purposes of the cost 

analysis.

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.L below, 

the construction permits issued by EPA to-date under the 

 

CO2 Storage and Sink Enhancement Options, Final Technical Report 

Prepared by Tennessee Valley Authority for DOE.

254 As noted above, other sequestration-related costs are also 

estimated, including injection wells and equipment, pore volume 

acquisition, and long-term-liability. NETL (2013) pp. 49-50.

255 Overview of Monitoring Requirements for Geologic Storage 

Projects. IEA Greenhouse Gas R&D Programme, Report Number 

PH4/29, November 2004.

256 Economic Evaluation of CO2 Storage and Sink Enhancement 

Options, Tennessee Valley Authority, NETL and EPRI, December 

2002.
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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. Moreover, the company indicated it fully expected 

to be able to do so at full scale and explained how.257 For 

discussion of 40 CFR Part 98 subpart RR (the Greenhouse Gas

Reporting Program requirements for geologic sequestration), 

including costs associated with compliance with those 

requirements, see section V.L below.

J. Achievable Emission Reductions Utilizing Partial CCS

Although the definition of “standard of performance” does 

not by its terms identify the amount of emissions from the 

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 

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 

 

257 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.
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factor to be weighed when determining the optimal standard for 

controlling ... emissions”).258 This is consistent with the Court’s 

statements in Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 

(D.C. Cir. 1973) 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 

500 MW coal-fired SCPC meeting the final standard of 1,400 lb

CO2/MWh-gross will emit about 640,000 fewer metric tons of CO2

each year than that new unit would have emitted otherwise. That

is equivalent to taking about 135,400 vehicles off the road each 

year259 and will result in over 25,000,000 fewer metric tons of 

CO2 in a 40-year operating life.

For comparison, see Table 13 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 

 

258 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.”

259 Using U.S. EPA Office of Transportation and Air Quality 

(OTAQ) estimate of average vehicle emissions of 4.7 tonnes/year. 
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significant, they are reasonably within the range of emission 

reductions that are currently being achieved now in existing 

facilities. 

Table 13. 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 

New 500 MW SCPC plant 636,300 

Coffeyville Fertilizer 700,000 

Boundary Dam #3 1,000,000 

Petra Nova/NRG WA Parish 1,600,000 

Dakota Gasification 3,000,000 

2013 CO2 supplied to U.S. EOR operations260 60,000,000 

K. Further Development and Deployment of CCS Technology

Researchers at Carnegie Mellon University (CMU), have 

studied that history and the technological response to 

environmental regulations. 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 

 

260 Greenhouse Gas Reporting Program, data reported as of August 

18, 2014.
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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.

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 FGD units didn't perform well as the 

technology at that time was poorly understood and there was 

little or no prior experience on coal-fired power plants.261 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 good 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 flue gas desulfurization 

(FGD) scrubber technologies. 

While R&D efforts were essential to achieving improvements

in FGD scrubber technology – and are also very important to 

 

261 “The Influence of Government Actions on Innovative Activities

in the Development of Environmental Technologies to Control

Sulfur Dioxide Emissions from Stationary Sources”, PhD Thesis of 

M.R. Taylor, Engineering and Public Policy, Carnegie Mellon 

University (2001).
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improving carbon capture technologies, the influence of 

regulatory actions that establish commercial markets for 

advanced technologies cannot be minimized.

L. Geologic and Geographic Considerations

In the following sections of the preamble, we discuss 

issues associated with the disposition of captured CO2: the “S” -

sequestration – in CCS. We show that geologic sequestration (GS)

capacity is available domestically in the form of geologic 

formations (e.g., deep saline formations) and EOR sites in most 

areas of the country. Where such GS capacity is unavailable, 

electricity demand in those areas can be served by coal-fired 

power plants built in neighboring areas with GS. For other of 

those areas, coal-fired power plants are either not being built 

due to state law prohibitions against building such units, or 

other available compliance alternatives exist allowing a new 

coal-fired power plant meeting the promulgated NSPS to be sited. 

We further show that GS can be conducted safely, storing 

the sequestered CO2 without environmental release for geologic 

time periods. Sequestration is already well proven. CO2 has been 

retained underground for eons in geologic (natural) repositories 

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 
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monitoring and reporting requirements of the Greenhouse Gas 

Reporting Program, 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 L of this preamble).

Geologic sequestration (GS) (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 

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).262

These mechanisms are functions of the physical and chemical 

properties of CO2 and the geologic formations into which the CO2

 

262 See, e.g., USEPA. 2008. Vulnerability Evaluation Framework for 

Geologic Sequestration of Carbon Dioxide.
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stream is injected. Subsurface formations suitable for GS of CO2

captured from affected EGUs are geographically widespread 

throughout most parts of the United States.

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.263 For 

example, CO2 has been trapped for more than 65 million years in 

the Jackson Dome, located near Jackson, Mississippi.264 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.265

GS is feasible in different types of geologic formations 

including deep saline formations (formations with high salinity 

 

263 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.

264 Intergovernmental Panel on Climate Change. (2005). Special 

Report on Carbon Dioxide Capture and Storage.

265 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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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 

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. As shown in the 

figure, there are 39 states for which onshore and offshore deep 

saline formation storage capacity has been identified.266 EOR 

operations are currently being conducted in 12 states. An 

additional 17 states have geology that is amenable to EOR 

operations. There are 10 states with operating CO2 pipelines and 

23 states that are within 150 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.267 Enhanced coalbed methane recovery is the process of 

injecting and storing CO2 in unmineable coal seams to enhance 

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

 

266 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.

267 Other types of opportunities include organic shales and 

basalt.
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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.268 The 

availability of unmineable coal seams is shown in Figure 1

below.

As discussed below in Sections K.1 and K.2 of this 

preamble, 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 against coal-fired power 

plants.269

 

268 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).

269 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.
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This image cannot currently be displayed.
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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 States270

1. 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.271 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 

 

270 Ventyx Velocity Suite Online. April 2015.

271 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.272 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.273 The seven partnerships include more than 400 

organizations spanning 43 states (and four Canadian 

provinces).274 RCSP project objectives are to inject at least one 

million metric tons of CO2. In April 2015, DOE announced that CCS 

 

272 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/.

273 http://energy.gov/fe/science-innovation/carbon-capture-andstorage-research/regional-partnerships.

274 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.

275

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 2013.276 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.277 No CO2 leakage has been reported from these sites, 

which further supports the availability of effective GS.

2. Availability of CO2 Storage via EOR

 

275 http://energy.gov/articles/milestone-energy-departmentprojects-safely-and-permanently-store-10-million-metric-tons

276 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.

277 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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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. 

The amount of CO2 used in an EOR project depends on the 

volume and injectivity of the reservoir that is being flooded 
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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 

specifications ensure EOR operators receive a known and 

consistent CO2 stream.
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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.278

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 L 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 23 states are within 150 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 where 

EOR is utilized include Alabama, Colorado, Louisiana, Michigan, 

Mississippi, New Mexico, Oklahoma, Texas, Utah, and Wyoming. 

 

278 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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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.279 According 

to data reported to the EPA’s Greenhouse Gas Reporting Program 

(GHGRP), approximately 60 million metric tons of CO2 were 

supplied to EOR in the United States in 2013.280 Approximately 70 

percent of this total CO2 supplied was produced from natural 

(geologic) CO2 sources and approximately 30 percent was captured 

from anthropogenic sources.281

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 

 

279 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.

280 Greenhouse Gas Reporting Program, data reported as of August 

18, 2014.

281 Greenhouse Gas Reporting Program, data reported as of August 

18, 2014.
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significantly increase the application of EOR to areas outside 

of current operations.282 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.283 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 

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. 

 

282 “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.

283 “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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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.

284 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 

formations. In a separate study in the SACROC Unit, the 

Texas Bureau of Economic Geology conducted an extensive 

 

284 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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groundwater sampling program to look for evidence of CO2

leakage in the shallow freshwater aquifers. No evidence 

of leakage was detected.285

 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 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.286 The International Energy Agency Greenhouse 

Gas Programme developed a best practices manual for CO2

monitoring at EOR sites based on the comprehensive 

 

285 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.

286 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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analysis of surface and subsurface monitoring methods

applied over the 10 years.287

 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 K.1 above).288 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.289 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 K.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. 

 

287 Hitchon, B. (Editor), 2012, Best Practices for Validating CO2

Geological Storage: Geoscience Publishing, p. 353.

288 http://www.beg.utexas.edu/gccc/cranfield.php.

289 http://www.beg.utexas.edu/gccc/cranfield.php.
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However, some commenters maintained that the EPA’s information 

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.290 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.291 Other 

commenters noted significant geographic disparity in GS site 

availability, claiming absence of sites in southeastern areas of 

the country.292

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 K.3 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). In addition, there are alternative means of complying 

with the final standards of performance which do not necessitate 

 

290 Comments of Southern Co., p. 38.

291 Comments of AEP pp. 93, 96.

292 Comments of Duke Energy, pp. 24-5; UARG, pp. 53, 57 citing 

Cichanowicz (2012).
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use of partial CCS, so any siting 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.

3. 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. For example, 

these carbonate materials have been used in the construction 
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industry and, more recently and innovatively, in cement 

production processes to replace Portland cement.

For example, 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.293

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. 

Alternative technologies that use captured CO2, such as the 

Skyonics project, are innovative advancements for CO2 utilization 

that are under development. However, consideration of how these 

emerging alternatives could be used to meet the performance 

standard involves understanding the ultimate fate of the 

captured CO2 and the degree to which the method permanently 

isolates the CO2 from the atmosphere. Unlike GS, currently there 

is not a monitoring and reporting mechanism to demonstrate that 

these alternative end uses of captured CO2 would result in 

permanent sequestration of the CO2. Therefore, they cannot be 

 

293 http://skyonic.com/technologies/skymine.
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used to meet the performance standard at this time. As these 

alternative technologies are developed, the EPA is committed to 

working collaboratively with stakeholders to evaluate the 

efficacy of alternative sequestration technologies, address any 

regulatory hurdles, and develop appropriate monitoring and 

reporting protocols in the future.

4. Availability of Existing or Planned CO2 Pipelines

CO2 has been transported via pipelines in the United States 

for nearly 40 years. 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 2004.294

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 

 

294 “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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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 2015.295

 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 

 

295 “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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the Gulf Coast region.296 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.297

 Denbury completed the final section of the 325-mile Green 

Pipeline for transporting CO2 from Donaldsonville, 

Louisiana, to EOR oil fields in Texas.298 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.299 A proposed project by NRG (Petra Nova) would 

capture CO2 from a power plant in Fort Bend County, Texas 

for transport to EOR sites in Jackson County, Texas 

 

296 “2013 Annual Report”, Denbury, April 2014. Available at 

http://www.denbury.com/files/doc_financials/2013/Denbury_Final_0

40814.pdf.

297 “CO2 Sources”, Denbury, 2014. Available at:

http://www.denbury.com/operations/rocky-mountain-region/co2-

sources-and-pipelines/default.aspx. 

298 http://www.denbury.com/responsiblity/public-awareness/DenburyAware/default.aspx.

299 “CO2 Pipelines”, Denbury, 2014. Available at: 

http://www.denbury.com/operations/rocky-mountain-region/COsub2-

sub-Pipelines/default.aspx.
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through a proposed 82-mile CO2 pipeline.300 The project is 

anticipated to commence operation in 2016.301

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, 254 (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 

with a higher potential for adverse consequences. See 49 CFR 

 

300 “The West Ranch CO2-EOR Project, NRG Fact Sheet”, NRG, 2014. 

Available at: http://www.nrg.com/documents/business/pla-2014-

west-ranch-fact-sheet.pdf. 

301 “WA Parish Carbon Capture Project”, NRG, 2015. Available at: 

http://www.nrg.com/sustainability/strategy/enhancegeneration/carbon-capture/wa-parish-ccs-project/.
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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, which EPA has found to provide similar protective 

safeguards as the Department of Transportation regulations.302

See 79 FR 358-59 (Jan. 3, 2014). The EPA reiterates here its 

findings that existing controls over CO2 pipelines assure 

protective management, guard against releases, and assure that 

captured CO2 will be securely conveyed to a sequestration site. 

5. 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 

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 

 

302 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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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.

New York established emission standards of CO2 at 925 lb 

CO2/MWh for new and expanded base load fossil fuel-fired plants.

In May 2007, Montana Governor Schweitzer signed House Bill 

25, adopting a CO2 emissions performance standard for electric 

generating units in the state. House Bill 25 prohibits the state 

Public Utility Commission from approving new electric generating 
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units 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.

6. Coal by wire

In addition, as discussed in the proposal, electricity 

demand in states that may not have geological sequestration 

sites may be served by coal-fired electricity generation built 

in nearby areas with geological sequestration, which generation 

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 

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, 
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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 sum, subsurface formations suitable for GS of CO2

captured from affected EGUs are geographically widespread 

throughout many parts of the United States, including via deep 

saline formations or EOR. Characteristics of geologic formations 

may vary based on geography, but the mechanisms by which CO2 is 

trapped underground are well understood and proven. 

Additionally, CO2 pipelines have been operating for over 40 years 

in the United States and new pipeline projects continue to be 

proposed and built. Some states already impose emission limits 

that can be met only through CCS, and in the few states that do 

not have geologic conditions suitable for GS, or may not be 

located in close proximity to these areas, demand could be 

served by coal-fired generation that is sited in areas with GS.

M. Final Requirements for Disposition of Captured CO2

In 2010, the EPA finalized an effective and coherent 

regulatory framework to ensure that CO2 is safely sequestered --

that is, that CO2 can be injected and remain securely underground 

for geologic timeframes. The EPA developed these Underground 
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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 Greenhouse Gas 

Reporting Program (GHGRP). Information collected under the GHGRP 

provides a transparent means for the EPA and the public to 

continue to evaluate the effectiveness of GS. 

As explained below, these requirements help ensure that 

sequestered CO2 will remain in place, and provide the monitoring 

mechanisms to identify and address potential leakage using SDWA 

and CAA authorities. We note the near consensus in the public 
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responses to the Class VI rulemaking that saline and oil and gas 

reservoirs provide ready means for secure GS of CO2.

303

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 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.304 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.

 

303 “Most commenters encouraged 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).

304 40 CFR §144.3.
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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 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. 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 appropriate locations and CO2 streams are injected into 

suitable formations with a confining zone or zones free of 
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transmissive faults or fractures to ensure USDW 

protection.305,306 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.307 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.308

 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.309 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 movement of CO2 or other 

 

305 75 FR 77240 and 75 FR 77247 (December 10, 2010).

306 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.)

307 40 CFR §146.81(d).

308 40 CFR §146.95.

309 40 CFR §146.84(a).
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fluids into or between USDWs.310,311 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.312 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.313

 Well construction must use materials that can withstand 

contact with CO2 over the operational and post-injection 

life of the project.314 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 

 

310 40 CFR §146.84(c)(1)(3) and §146.90(d)(1).

311 40 CFR §146.81(d) and §146.84.

312 40 CFR §146.84(b)(2)(iv).

313 40 CFR §146.84(e)(1).

314 40 CFR §146.86(b).
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large-scale GS including buoyancy, corrosivity, and high 

sustained pressures over long periods of operation.315,316

 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.317 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.318 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 

 

315 75 FR 77250-52 (December 10, 2010); see also id. at 77234-35. 

Commenters were mistaken in asserting (without reference to 

Class VI provisions) that the EPA had ignored issues relating to 

CO2 properties when injected in large volumes in supercritical 

state into geologic formations.

316 40 CFR §146.88.

317 40 CFR §146.90.

318 40 CFR §146.90(j).
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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 sitespecific basis. 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.319

 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.320

 Financial responsibility demonstrations are required to 

ensure that funds will be available for all area of review 

corrective action, injection well plugging, post-injection 

 

319 40 CFR §146.90(h)(1) and 75 FR at 77259 (Dec. 10, 2010).

320 40 CFR §146.94.
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site care, site closure, and emergency and remedial 

response.321

 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.322 The injection well also must be 

plugged, and following a demonstration of non-endangerment 

of USDWs by the Class VI owner or operator, the site must 

be closed.323,324 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.325 Following 

successful closure, the facility property deed must record 

that the underlying land is used for GS.326

 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, 

 

321 40 CFR §146.85.

322 40 CFR §146.93.

323 40 CFR §146.92.

324 40 CFR §146.93.

325 40 CFR §146.93(b).

326 40 CFR §146.93(c).
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well construction, and financial responsibility.327,328,329,330,331,332

The EPA has also prepared and made available for public comment 

draft guidance documents on transitioning Class II wells to 

Class VI wells; well plugging, post-injection site care, and 

site closure; and recordkeeping, reporting, and data 

management.333,334,335,336

To inform the development of the UIC Class VI rule, the EPA 

solicited stakeholder input and reviewed ongoing domestic and 

 

327

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r1

3004.pdf.

328

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r1

3005.pdf.

329

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r1

3001.pdf.

330

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r1

1017.pdf.

331

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r1

1020.pdf.

332

http://water.epa.gov/type/groundwater/uic/class6/upload/uicfinan

cialresponsibilityguidancefinal072011v.pdf.

333

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p1

3004.pdf. See also 40 CFR §144.19.

334

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p1

3005.pdf.

335

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p1

3001.pdf.

336

http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p1

3002.pdf.
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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 

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.337

Following the operational period, Archer Daniels Midland plans a 

post-injection site care period of ten years.338 In September 

2014, the EPA also issued four Class VI injection well permits 

(to construct) to the FutureGen Industrial Alliance project in 

 

337 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.

338 http://www.epa.gov/region5/water/uic/adm/.
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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.339 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.340

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.341

The permitting of these projects illustrates that permit 

applicants were able to address perceived challenges to issuance 

 

339 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.

340 http://www.epa.gov/r5water/uic/futuregen/.

341 http://www.epa.gov/r5water/uic/futuregen/;

http://www.epa.gov/region5/water/uic/adm/.
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of Class VI permits. These permits demonstrate the EPA’s view 

that these projects are capable of safely and securely 

sequestering large volumes of CO2 -- including from steam 

generating units -- for geologic timeframes since the EPA would 

not otherwise have issued the permits. 

b. Class II requirements. As explained in section K.2 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 industry experience in operating EOR projects. The 

CO2 injection wells used for EOR are regulated through the UIC 

Class II program.

342 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 gas-related 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 

 

342 40 CFR §144.6(b).
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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 Greenhouse Gas Reporting Program 

(GHGRP) 

The GHGRP requires reporting of facility-level GHG data and 

other relevant information from large sources and suppliers in 

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 40 

CFR 60.46Da(h)(5) and 40 CFR 60.5555(d). Taken together, these 

requirements ensure that the amount of captured and sequestered 

CO2 will be tracked as appropriate at project- and nationallevels, 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 
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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.343 CO2 suppliers are 

required to report the annual quantity of CO2 transferred offsite 

and its end use, including GS.344

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.345

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 40 CFR 

60.46Da(h)(5) and 40 CFR 60.5555(d) to use the phrase “If your 

affected unit captures CO2” in place of the phrases “If your 

affected unit uses geologic sequestration” and “If your affected 

 

343 40 CFR §98.420(a)(1).

344 40 CFR §98.426.

345 40 CFR §98.426(h).
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unit employs geologic sequestration”, respectively. 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.

346

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

sequestered using a mass balance approach; and report annual 

monitoring activities.347,348,349,350 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.351 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.352

 

346 40 CFR §98.440.

347 40 CFR §98.446.

348 40 CFR §98.448.

349 40 CFR §98.446(f)(9) and (10).

350 40 CFR §98.446(f)(12).

351 See 75 FR at 77263 (Dec. 10, 2010). 

352 40 CFR §98.448(a)(1).
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 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.353

 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.354

 An approach for establishing the expected baselines for 

monitoring CO2 surface leakage. Baseline data represent 

pre-injection site conditions and are used to identify 

potential anomalies in monitoring data.355

 A summary of considerations made to calculate sitespecific variables for the mass balance equation. Sitespecific 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.356

 

353 40 CFR §98.448(a)(2).

354 40 CFR §98.448(a)(3).

355 40 CFR §98.448(a)(4).

356 40 CFR §98.448(a)(5).
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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.357

Under this final rule, any well receiving CO2 captured from 

an affected source, be it a Class VI or Class II well, must 

report under subpart RR.358 As explained below in Section L.5.a, 

a 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 

 

357 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.

358 See §60.46Da(h)(5) and §60.5555(d).
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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, as explained below, the practical 

effect of these complementary technical requirements 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. 

 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. 
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 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 L.1, the UIC 

Class VI rule provides a framework to ensure the safety of 

underground injection of CO2 such that USDWs are not endangered. 

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 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 L.1.
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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 

for geologic timeframes (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.359

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 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 

 

359 40 CFR §146.82(a) and (c).
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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. 

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.360 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 

 

360 40 CFR § 146.94(b)
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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, which are specifically designed to ensure that the 

CO2 and any incidental associated substances derived from the 

source 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...”361

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 

 

361 79 FR at 353 (January 3, 2015) (Final Hazardous Waste 

Management System: Conditional Exclusion forCarbon Dioxide (CO2) 

Streams in Geologic Sequestration Activities under subtitle C of 

RCRA). See Section L.5.c below.
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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 L.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. 

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.
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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 

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 to air.

CO2 injected via Class II wells becomes sequestered by the 

trapping mechanisms described above in Section L.3.a. 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 
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period. Subpart RR provides a CO2 accounting framework that will 

enable 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, commenters opined on the possibility of sporadic 

CO2 supply due to the nature of EGU operation.362

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 J.1). The BSER determination and regulatory impact 

analysis for this rule relies on GS in deep saline formations.

363

 

362 See, e.g. Comments of Southern Company, p. 41.

363 The EPA anticipates EOR projects may be early GS projects 

because these formations have been previously well characterized 
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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 2013.364 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 

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 

 

for hydrocarbon recovery, likely already have suitable 

infrastructure (e.g., wells, pipelines, etc.), and have an 

associated economic benefit of oil production.

364 Greenhouse Gas Reporting Program, data reported as of August 

18, 2014.
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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, 

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 
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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. 

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.365

 

365 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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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 Section K, 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 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 K.2). 

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. 
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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 

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 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 
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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 

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 
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sequestered CO2 to either underground drinking water sources or 

to the ambient air.366

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 

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.

5. Must the standard of performance for CO2 include CAA

requirements on the sequestration site? 

 

366 “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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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 

requirements governing a ‘standard of performance’” (emphasis 

original).367

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 

 

367 Comments of UARG, pp. 37, 38.
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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” under section 111. 

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 
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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 

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, and 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 
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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 

stringent and that a 50-year post-injection site care period is 

unnecessarily long.368 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 these comments in more detail in the 

Response to Comment Document.

6. 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 

 

368 Comments of UARG, p. 63.
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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:369

 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 

 

369 “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
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permitted EOR operation, the key factor in determining 

the potential need to transition a 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.370

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 

requirements of GHGRP subpart RR.371 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 is prohibitive to the 

use of EOR. 

 

370 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. 

371 See e.g., comments of UARG, p, 63; Southern, p. 37; American 

Petroleum Institute pp. 40-50.
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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.372 Monitoring costs are estimated to range from $0.02 

per metric ton (base case scenario) to approximately $2 per 

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.

373 Thus, the argument that EOR 

 

372 Subpart RR costs are presented in 2008 US dollars.

373 “Near Term Projections of CO2 Utilization for Enhanced Oil 

Recovery”. DOE/NETL-2014/1648. April 2014. 
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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.

374 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. 

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 

 

374 http://www.irs.gov/irb/2009-44_IRB/ar11.html. The section 45Q 

tax credit for calendar year 2014 was $10.75 per metric ton of 

qualified CO2 that is captured and used in a qualified EOR 

project and $21.51 per metric ton of qualified CO2 that is 

capture and used in a qualified non-EOR GS project. 

http://www.irs.gov/irb/2014-27_IRB/ar12.html.
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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.375 Nevertheless, to reduce potential 

uncertainty regarding the regulatory status of CO2 streams under 

RCRA Subtitle C, and in order to facilitate the deployment of 

geologic sequestration, the EPA recently concluded a rulemaking 

to exclude certain CO2 streams from the RCRA definition of 

hazardous waste.376 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 

 

375 No hazardous waste listings apply to CO2 streams. Therefore, a 

CO2 stream could be defined as a hazardous waste only if it 

exhibits one or more of the hazardous characteristics. 79 FR 355 

(Jan 3. 2014).

376 79 FR 350 (Jan. 3, 2014).
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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)).377

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 

 

377 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 

(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 any 

impediment to use of anthropogenic CO2 for EOR.
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frameworks, or competing, inconsistent state laws.378 Other 

commenters noted the lack of long-term liability insurance, and 

noted uncertainties regarding long-term liability generally.379

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 

storage.

380 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.381 As 

noted earlier, both the Archer Daniels Midland 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. 

 

378 See e.g. Comments of Duke Energy, p. 28; UARG, p. 62; AEP, p. 

91.

379 See e.g. Comments of UARG, pp. 26, 62; EEI, p. 92; Duke 

Energy, pp. 27, 28.

380 Intergovernmental Panel on Climate Change. (2005). Special 

Report on Carbon Dioxide Capture and Storage.

381 http://www.epa.gov/climatechange/Downloads/ccs/CCS-Task-ForceReport-2010.pdf
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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.382

Other commenters noted more generally that site characterization 

issues can be time-consuming and difficult, and quoted studies 

suggesting that it could take 5 years to obtain a Class VI 

permit.383

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 K). 

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 

 

382 AEP Comments at pp. 93, 96. 

383 See e.g. Comments of UARG, p. 55, citing to Cichanowitz CCS 

Report (2012).
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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 

expected to be able to do so at full scale and explained how.384

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 

 

384 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.
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construction permits for Class VI wells involved far fewer 

injection wells than AEP references.385

N. Options That Were Considered 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.

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 

 

385 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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implementation of CCS), such as a supercritical386 pulverized 

coal (SCPC) or a supercritical CFB boiler, or a modern, wellperforming IGCC unit.

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 

estimates387, a newly constructed subcritical PC unit firing 

bituminous coal would emit approximately 1,800 lb CO2/MWh-gr, a 

new SCPC unit using bituminous coal would emit nearly 1,700 lb 

CO2/MWh-gr, and a new IGCC unit388 would emit about 1,450 lb 

 

386 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.

387 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).

388 “Case 1” from 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).
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CO2/MWh-gr.389 Emissions from comparable sources utilizing subbituminous coal or lignite will have somewhat higher CO2

emissions.390

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, the majority of the most 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. Coal-fired power plants that have come on-line the 

most recently include AEP’s John W. Turk, Jr. Power Plant, which 

is a 600 MW ultra-supercritical391 PC (USCPC) facility located in 

the southwest corner of Arkansas, and Duke Power’s Edwardsport 

plant, which is a 618 MW “CCS ready” IGCC unit located in Knox 

County, Indiana. The majority of new coal-fired power plants 

that were brought on-line in 2010 or later have utilized 

 

389 The comparable emissions on a net basis are: subcritical PC –

1,890 lb CO2/MWh-net; supercritical PC – 1,770 lb CO2/MWh-net; 

and IGCC – 1,720 lb CO2/MWh-net.

390 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).

391 Ultra-supercritical (USC) and advanced ultra-supercritical (AUSC) are terms often used to designate a coal-fired power plant 

design with steam conditions well above the critical point.
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supercritical boiler technology.392 And those units that 

initiated operation in 2010 or later were conceived 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. 

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 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, 

 

392 Exceptions would include a few smaller plants (e.g., less than 

300 MW) that are CHP units and a few subcritical PC and CFB 

sources.
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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 

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 
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boiler.

As is shown in Section [x.x], 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.”393

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 caselaw, encouraging the 

development and implementation of advanced control technology 

must also be considered. Consideration of this factor confirms 

the EPA’s decision not to identify highly efficient generation 

technology (without CCS) as the BSER. At present, CCS 

 

393 Sierra Club, 657 F.2d at 327 & n. 83.
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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.

The International Panel on Climate Change (IPCC) recently 

released its Fifth Assessment report394, 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 

 

394 IPCC, Working Group III, Climate Change 2014: Mitigation of 

Climate Change, http://mitigation2014.org/report/publication/
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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.”395

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-gross, would not serve to promote the increased 

deployment and implementation of CCS. The commenters argued that 

such a 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.

 

395 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).
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The EPA does not agree with these arguments and, in 

particular, does not see how a standard that does not require 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 require the installation of advanced 

control equipment lead to increased use of that control 

equipment, and 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 

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 coal-fueled generation are to 

comply with potential future climate regulations 

without prematurely retiring efficient, cost-effective 

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 
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uncertainty also makes it difficult to attract 

partners to help fund the industry’s share.396

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 

(supercritical) coupled with government subsidies to advance and 

promote CCS technology. As we will show later, the final 

standard that we are issuing in this action is less stringent 

than the proposed level and can be met at a lower cost than the 

proposed standard. Further, the record and current economic 

conditions (fuel costs, renewables, demand growth, etc.) show 

that non-economic factors such as a desire for fuel diversity 

will likely drive future development of new coal-fired EGUs. In 

that scenario, a cost-reasonable standard is, in fact, 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 most IGCC units, 

the final standard of performance can be met simply by co-firing 

 

396 http://www.aep.com/newsroom/newsreleases/?id=1704
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a small amount of natural gas. Some commenters argued that IGCC 

is an advanced technology that, like CCS, should be promoted. 

The EPA 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-gross will not 

itself deter installation of IGCC technology, by the terms of 

the commenters’ own argument.397

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 

 

397 Commenters stated: While the final standard of performance 

should not deter the installation of new IGCC generation, the 

technology still faces hurdles due to its higher cost relative 

to the cost of a new SCPC plant and, more importantly, relative 

to the cost of new NGCC facility.
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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. 

In the proposal for newly constructed sources (January 2014 

proposal), 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 even greater than 

at proposal. The EPA thus is not selecting full capture CCS as 

BSER.

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 
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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 

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 potential 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 potential hourly increase in CO2 emissions (mass 

per hour) of less than or equal to 10 percent ("small" 

modifications), is not issuing final standards for these sources 

in this action, and is withdrawing the proposed standards for 

these sources. 

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 [x.x] (General 

Applicability) and section [x.x] (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 
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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 

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.

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 

potential hourly CO2 emissions (mass per hour) of more than 10 

percent as compared to the source’s potential to emit 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 potential 

hourly CO2 emissions (mass per hour) of 10 percent or less 

compared to the source’s potential to emit during the previous 5
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years, the EPA is not finalizing any standard or other 

requirements, and in a separate action today is withdrawing the 

June 2014 proposal with respect to these sources.

As we discussed in the June 2014 proposal, the EPA has

historically been notified of only a limited number of NSPS 

modifications 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 reconstruction or replacement of steam turbines and 

other equipment upgrades that result in substantial increases in 

a unit’s potential 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 potential hourly CO2 emissions, as well as on the 

types of measures available to control emissions from sources 
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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 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.

To be clear, the EPA is not reaching a final decision that 

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.

In deferring issuance of standards of performance for those 

sources that conduct modifications resulting in a potential 

hourly increase in CO2 emissions of less than or equal to 10 
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percent, the EPA is exercising its discretion to propose and 

promulgate standards covering sources within a source category 

in a sequential manner, under appropriate circumstances, such as 

those present here, consistent with the case law that authorizes 

agencies to establish a regulatory framework in an incremental 

fashion, that is, a step at a time.398,399

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 reconstruction or replacement of steam turbines and other 

equipment upgrades that would significantly increase a unit's 

 

398 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 (DC Cir. 1998), City 

of Las Vegas v. Lujan, 891 F.2d 927, 935 (DC Cir. 1989), 

National Association of Broadcasters v. FCC, 740 F.2d 1190, 

1209–14 (DC Cir. 1984).

399 As the D.C. Circuit stated in 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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capacity to burn more fossil fuel, thereby resulting in large 

emissions increases. Major upgrades such as these could increase 

a steam generating unit's potential hourly CO2 emissions by well 

over 10 percent.

400

Therefore we are setting the threshold between “large”

modifications and “small” modifications subcategory at 10 

percent, a level commensurate with the magnitude of the 

emissions increases that could result from these types of 

projects, and we are issuing a final standard of performance for 

those sources that conduct modifications resulting in potential 

hourly CO2 emission increases that exceed that threshold. We are 

not issuing standards of performance for those sources that 

conduct modifications resulting in a potential hourly increase 

of CO2 emissions of less than or equal to 10 percent. 

Therefore, in a separate action (published in a separate 

notice in the Federal Register today), the EPA is withdrawing 

the proposed standards for those sources that conduct 

modifications resulting in a potential 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. Utilities, states and others should be aware that the 

 

400 See e.g., Power Engineering, Steam Turbine Upgrades Boost 

Plant Reliability, Efficiency, available at http://www.powereng.com/articles/print/volume-116/issue-11/features/steamturbine-upgrades-boost-plant-reliability-efficiency.html.
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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 part C or other CAA requirements.

The EPA notes that some commenters expressed concern that a 

number of existing fossil steam generating units, in order to 

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 
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potential CO2 hourly emissions. Nevertheless, 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 potential hourly CO2 emissions 

associated with such modifications would generally be small and 

would therefore generally not subject such modifications to the 

standards of performance that the EPA is finalizing today for 

modified steam generating units with large increases in 

potential hourly CO2 emissions.

We note that modified steam generating units that are not 

subject to the standard of performance finalized in this rule

would be existing sources subject to section 111(d).401

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 

is the affected source’s own best potential performance as 

 

401 Any source that undergoes a modification resulting in CO2 

increases of less than 10 percent will continue 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 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 the modifications with small CO2 increases, 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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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 source’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—

that is, the modified source would be required to meet a unit-
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specific emission limit determined by the affected source’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. 

C. BSER Criteria 
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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”. 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 

associated costs, and thus that the net costs of heat rate 

improvements associated with reducing CO2 emissions from 

affected EGUs are relatively low.
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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. 

3. Emission Reductions

This approach would achieve reasonable reductions in CO2

emissions from the affected modified units as those units will 

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. Technology Promotion 

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 
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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.

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) 
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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 

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 EPA's decision that 

these technologies are not BSER. In contrast, 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 are finalizing 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 
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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 

reasonable costs, and some opportunity for technological 

innovation. The proposed emission standard for these sources was 

1,900 lb CO2/MWh-net for units with a heat input rating of 

greater than 2,000 MMBtu/h and 2,100 lb CO2/MWh-net 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-outputbased 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 
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2,000 lb CO2/MWh-gross for large units and 1,800 to 2,200 lb 

CO2/MWh-gross 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.

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-net 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 
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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 

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-gross for sources with a heat input rating of 
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greater than 2,000 MMBtu/h and 2,000 lb CO2/MWh-gross 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 

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, 

Modified, and Reconstructed Stationary Combustion Turbines
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This section summarizes the final applicability

requirements, BSER determinations, and emission standards for 

newly constructed, modified, and reconstructed stationary 

combustion turbines. We explain our rationale for these final 

decisions in Section IX of this preamble.

A. Applicability Requirements

We are finalizing emission standards for newly constructed, 

modified, and reconstructed stationary combustion turbines that 

(1) have a base load rating for fossil fuels greater than 250 

MMBtu/h and (2) serve a generator capable of selling more than 

25 MW of electricity to the grid. We also are finalizing 

applicability requirements that will exempt stationary 

combustion turbines that are dedicated peaking units, dedicated

non-fossil units, or are physically incapable of burning natural 

gas (i.e., not connected to a natural gas pipeline), waste 

combustors and incinerators (units subject to subparts Eb or 

CCCC of this part), as well as the large majority of industrial 

combined heat and power units from the final emission standards. 

Specifically, the final emission standards do not apply to 

stationary combustion turbines subject to a federally 

enforceable permit condition limiting annual electric sales to 

the specific design efficiency of the combustion turbine 

multiplied by the unit’s potential electric output or less or 

restricting annual fossil fuel use to 10 percent or less of a 
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unit’s heat input capacity. Finally, the final emission 

standards do not apply to combined heat and power units that are 

subject to a federally enforceable permit condition limiting 

net-electric sales to the unit’s design efficiency multiplied by 

the unit’s potential output or 219,000 MWh, whichever is 

greater.

B. Best System of Emission Reduction

We are finalizing the same BSER as proposed. For newly 

constructed, modified, and reconstructed stationary combustion 

turbines. The BSER is the use of modern, efficient combined 

cycle technology. 

C. Final Emission Standards

For all newly constructed, modified, and reconstructed

natural gas-fired combustion turbines, we are finalizing an 

emission standard of 1,000 lb CO2/MWh-gross, calculated on a 12-

operating month rolling average basis. We are also finalizing an 

optional emission standard of 1,080 lb CO2/MWh-net, calculated on 

a 12-operating month rolling average basis. 

IX. Rationale for Final Standards for Newly Constructed, 

Modified, and Reconstructed Stationary Combustion Turbines

This section discusses three inter-related topics (1) 

applicability criteria, (2) BSER, and (3) achievability of the 

standards for combustion turbines. We summarize what was 

proposed, relevant comments received with our responses, and the 
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rationale for the final determinations. The rationale includes a 

discussion on the role of simple cycle turbines in providing 

backup power in regions with large amounts of intermittent 

renewable generation. The achievability discussion explains how 

the applicability criteria taken together with our BSER 

determination ensure that the standards are achievable by 

affected units. 

Applicability and subcategorization are closely tied to the 

required emission standards, and we are carefully considering 

them together. For example, some owners/operators may see an 

inherent value in not being subject to subpart TTTT, regardless 

of the requirements for that particular type of unit under 

subpart TTTT, and certain exemption criteria could lead to a 

perverse incentive to install new units or run units in a way

that increases CO2 emissions above the baseline emission rate. 

Furthermore, the EPA recognizes that energy industry trends have 

evolved, and we are adjusting our proposed approach to reflect 

these changes. 

For the proposed applicability to combustion turbines, the 

EPA used the 1/3 electric sales criteria, in part because it 

already exists in regulatory context (e.g., the coal-fired EGU 

NSPS) and would allow for consistency between regulations. Our 

understanding at proposal was that the 1/3 electric sales 

criterion would essentially exclude all simple cycle turbines 
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and would serve to distinguish between peaking (i.e., low 

capital cost, flexible, but relatively inefficient simple cycle 

units) and intermediate and base load combustion turbines (i.e., 

higher capital cost, less flexible, but relatively efficient 

combined cycle units). Based on public comments however, our 

understanding of the potential future roles of combustion 

turbine EGUs has evolved. The growth of generation from 

intermittent renewable sources has created a perceived need for 

additional cycling generation that operates outside of the 

traditional roles of simple and combined cycle combustion 

turbines. In response, the market is developing new technologies 

to fill this need perceived by end users of combustion turbines. 

Some manufacturers have developed high efficiency simple cycle 

turbines. While these newer turbines have higher capital costs 

than older simple cycle turbine designs, they are significantly 

more efficient and have maintained similar flexibilities (e.g., 

ability to start and change load rapidly) as previous designs. 

In contrast, other manufacturers have developed fast start 

flexible combined cycle units specifically to fill this role. 

These newer combined cycle designs have lower design 

efficiencies than base load combined cycle designs, but are able 

to start up more quickly to respond to rapid changes in 

electricity demand. Therefore, there is no longer a clear 
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distinction between the role of simple cycle and combined cycle 

turbines. 

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 an 

applicability determined strictly on design and permit 

restrictions and independent of actual operating 

characteristics. 

1. Proposed Applicability

The proposed five applicability criteria for combustion 

turbines were that a 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 onethird of its potential net-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 did not propose CO2 standards for two types of combustion 

turbines that are currently subject to criteria pollutant 
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standards under subpart KKKK (the combustion turbine criteria 

pollutant NSPS). The first type was stationary combustion 

turbines that were constructed for the purpose of selling or 

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. The second type of unit was non-natural gas-fired 

stationary combustion turbines (i.e., combustion turbines that 

actually combust 90 percent or less natural gas on a 3 year 

rolling average basis). Under the proposed approach, 

applicability with the GHG NSPS could change on an annual basis 

depending on actual electric sales and the composition of fuel 

burned. While the proposed applicability criteria did not 

explicitly exempt simple cycle combustion turbines, we concluded 

at proposal that it would as a practical matter exclude the vast 

majority of simple cycle turbines because, historically, simple 

cycle turbines have operated as peaking units and, on average, 

have sold less than five percent of their potential electric 

output on an annual basis. 

We solicited comment on a range of issues related to the 

general applicability of the EGU GHG NSPS to combustion 

turbines. In conjunction with the proposed one-third sales 

criterion, we solicited comment on finalizing an electric sales 

criterion between 20 to 40 percent of the potential electric 

output or basing the electric sales criterion on the design 
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efficiency of the combustion turbine (i.e., the sliding scale 

approach). Under the sliding scale approach, more efficient 

combustion turbines would be able to sell a greater portion of 

their potential electric output, relative to less efficient 

combustion turbines, prior to triggering the electric sales 

criterion. We also solicited comment on whether the 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 electric sales 

criterion for combustion turbines to eliminate any incentive to 

install multiple, exempt, small, and less efficient stationary 

combustion turbines. We also solicited comment on whether to 

provide an explicit exclusion for all simple cycle combustion 

turbines regardless of the amount of electricity sold. Finally, 

we solicited comment on how to implement the proposed actual 

electric sales and actual fuel use applicability criteria 

evaluated as 3-year rolling averages during the first three 

years of operation, and we requested comment on appropriate 

monitoring, recordkeeping, and requirements. We specifically 

solicited comment on whether these proposed requirements raise 

implementation issues because they are based on source operation 

after construction has occurred.

In both the January 2014 proposal for newly constructed 

EGUs and the June 2014 proposal for modified and reconstructed 
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EGUs, the EPA solicited comment on finalizing a broad 

applicability approach. Specifically, we solicited comment on 

whether we should completely remove the electric sales (both the 

actual sales and “constructed for the purpose” criteria) and 

fuel use criteria components from the general applicability 

framework (that establishes the sets of sources that are subject 

to CAA section 111 standards). Instead the actual electric sales 

and fuel use thresholds would serve as subcategorization 

criteria for distinguishing classes of EGUs and subcategoryspecific emissions standards. Under a broad applicability 

approach, the “constructed for the purpose of” would be 

completely eliminated and applicability for combustion turbines 

would be determined by the base load rating (i.e., greater than 

250 MMBtu/h) and the capability to sell power to a utility 

distribution system (i.e., serving a generator capable of 

selling more than 25 MW to a utility distribution system). In 

contrast to the five proposed applicability criteria, under the 

broad applicability approach, affected units, including simple 

cycle peaking and oil-fired combustion turbines, would remain 

subject to the standard of performance regardless of their

actual electric sales or fuel use. The broad applicability 

approach is consistent with historical NSPS applicability 

approaches based on design criteria with different emission 

standards for subcategories distinguished by operating 
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characteristics. We solicited comment on all aspects of this 

"broad applicability approach," including the extent to which it 

would achieve the policy objectives of assuring that a simple 

cycle turbine and a combined cycle turbine are subject to the 

same standard if they sell more than the specified electric 

sales threshold to the grid.

We also requested comment on excluding electricity sold 

during system emergencies as counting toward net electric sales

for determining sales in excess of the electric sales threshold. 

The rationale included that simple cycle combustion turbines 

intended only for peaking applications might be required to 

operate above the proposed electric sales threshold if a major 

power plant or transmission line is unexpectedly unavailable for 

an extended period of time. The EPA concluded that this 

flexibility is appropriate if the unit is called upon to run 

after all other available generating assets are already running 

at full load. The definition of "system emergency" presented in 

the proposal was "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 
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the affected area, or for the specific affected facility to 

operate to avert loss of load." 

2. Comments on Applicability

We received comments specific to each one of the five 

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. The comments and 

rationale for applicability to dedicated non-fossil units (i.e., 

units that combust less than 10 percent fossil fuel) and 

industrial CHP are discussed in Section III of this preamble. 

For combustion turbines, we received few specific comments on 

the 10 percent fossil fuel threshold and the 90 percent natural 

gas threshold. Many commenters supported the general size 

thresholds (i.e., have a base load heat input rating greater 

than 250 MMBtu/h and serving a generator with a capacity greater 

than 25 MW) because these thresholds are consistent with the 

thresholds used in states participating in the Regional 

Greenhouse Gas Initiative (RGGI) and under Title IV programs. 

Other commenters opposed this threshold 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 sources 

because unaffected units have a competitive advantage in energy 

markets because these exempt units would not be required to 
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internalize the costs of compliance. The EPA received many 

comments on applicability of the proposed standards to simple 

cycle combustion turbines, the electric sales criteria (both the 

one-third sales relative to the potential electric output and 

the 219,000 MWh criteria), and the broad applicability approach.

Commenters from the power sector generally supported a 

complete exemption of simple cycle turbines. The rationale for 

these commenters included that simple cycle turbines are 

uniquely capable of achieving the ramp rates necessary to 

respond to emergency conditions and hourly variations in output 

from intermittent renewables. Commenters noted that simple cycle 

combustion turbines serve different purpose than combined cycle 

power blocks and that economics will drive the use of combined 

cycle 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 an electric sales criterion between 40 to 

60 percent. Some commenters supported the sliding scale approach 

and stated that incentives for manufacturers to develop and end 

users to purchase higher efficiencies combustion turbines could 

be directionally helpful towards mitigating concerns about a 
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monolithic national constraint on simple cycle capacity factors.

In contrast, others commented that fast response combined cycle 

units intended for peaking and intermediate load applications 

can achieve ramp rates comparable to simple cycle units. These 

commenters said that simple cycle turbines should be restricted 

to their historical role as peaking units and that the one-third 

electric sales criterion provides sufficient flexibility. Some 

commenters suggested that the one-third sales criterion could be 

reduced to 20 percent or lower without adverse impact on grid 

reliability. Commenters noted that a complete exclusion for 

simple cycle turbines creates an opportunity to evade the 

standard and could thereby increase GHG emissions by creating a 

regulatory incentive to install and operate less efficient 

unaffected units compared to more efficient affected units.

According to these respondents, any applicability distinctions 

should be based on utilization and function rather than purpose 

or technology. 

Commenters also noted that the 219,000 MWh electric sales 

criteria puts larger combustion turbines at a competitive 

disadvantage by distorting the market and could have the 

perverse impact of increasing GHG emissions. These commenters 

noted that the 219,000 MWh electric sales threshold permits 

combustion turbines smaller than about 80 MW to sell more than 

the proposed one-third electric sales threshold while larger, 
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more efficient combustion turbines are restricted to selling 

one-third of their potential electric output to avoid 

applicability of the proposed CO2 standard. This creates a 

regulatory incentive to install multiple less efficient 

combustion turbines instead of fewer more efficient combustion 

turbines and could have the unintended consequence of increasing

GHG emissions.

Commenters in general supported that net electric sales 

applicability use a 3-year rolling average instead of a single 

year average. However, commenters noted that the inconsistency 

between the 3 calendar year applicability and 12-operating month 

compliance period results in compliance issues. For example, a 

facility could burn greater than 90 percent natural gas over a 3 

year period, but could burn greater than 10 percent distillate 

oil during a 12-operatng month compliance period with the same 3 

year period. Since the CO2 content of distillate oil is higher 

than natural gas, even if the facility is operating at maximum 

efficiency it would exceed the proposed emission standard. The 

inconsistency creates similar issues for 12-operating month 

periods with low electric sales, but the 3 year sales exceed the 

applicability threshold.

In response to EPA's request for comments on whether the 

retrospective applicability requirements would create 

implementation issues, several permitting authorities opposed 
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proposed applicability provisions that could change 

applicability determinations from year-to-year because this 

approach would result in compliance issues and in difficulties 

in determining proper pre-construction and operating permit 

conditions. These permitting authorities said that in order for 

a source to avoid applicability of the NSPS, the source must be 

subject to a federally enforceable permit limit 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: which is intended 

to provide clear and predictable standards of performance for 

new sources that would apply when they begin operations.

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 or not the GHG standard 

applies to a proposed new unit. Commenter said EGUs undergoing 

permitting should be allowed to request limits in operating 

permit conditions in order to remain below the proposed rule's 

applicability provisions, 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 stated a preference for the "proposed applicability 

approach" over the "broad applicability approach." These 

commenters did not think it was necessary to require combustion 

turbines with low electric sales or non-natural gas-fired 

combustion turbines to be subject to GHG 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) since these units would be subject "no emissions 

standards." In addition, some commenters stated that use of the 

"broad applicability" approach under CAA section 111(b) 

proceedings is not appropriate because the plain language of the 

CAA prohibits establishment of applicability requirements under 

CAA section 111 that rely on "no emissions standard" as 

suggested by the EPA. These commenters stated that "no emission 

standard" is not a "standard of performance" as defined in CAA 

section 111(a)(1) because a "standard of performance" is defined 

as a "requirement of continuous emission reduction." In 

contrast, many other commenters supported inclusion of new 

simple cycle units within the scope of the CAA 111(b) 

applicability criteria so that similar, existing simple cycle 
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units would be subject to the CAA 111(d) standard (to preserve 

the discretion of state planners under section 111(d)). Numerous 

other commenters stated that all sources that sell electricity 

to the grid should be subject to the 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.

Multiple commenters supported exclusion of electricity 

generated as a result of a grid emergency from counting towards 

net sales when determining applicability. One commenter stated 

that in addition to declared grid emergencies, there are other 

circumstances that warrant emergency exemption under the rule, 

including extreme market conditions, limitations on fuel supply, 

and reliability responses. Another commenter stated that the 

definition of "system emergency" should be defined as "any 

abnormal system condition that the Regional Transmission 

Organization, Independent System Operators, or Control Area 

Administrator determines requires immediate automatic or manual 

action to prevent a limit loss of transmission facilities or 

generators that could adversely affect the reliability of the 

power system and therefore calls for maximum generation 

resources to operate in the affected area, or for the specific 
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affected facility to operate to avert loss of load." The 

commenter said this definition is appropriate because the 

benefits of operating these units to generate electrical power 

during emergency conditions outweigh any adverse impacts from 

short-term increases in CO2 emissions by units lower in the 

dispatch order.

Multiple commenters opposed the exclusion of grid 

emergencies when calculating a source's net electricity sales 

for rule applicability purposes because CAA section 111 emission 

standards must apply continuously, even during grid emergencies. 

The commenters stated that the EPA does not have the necessary 

authority under the CAA to suspend applicability of the standard 

during periods of "grid emergency". Some commenters stated that 

an exclusion is unnecessary, because the EPA possesses an 

effective mechanism to address the issue: The EPA Assistant 

Administrator for Enforcement is delegated the authority to 

advise a source that the government would not sue the source for 

taking certain actions during an emergency. Commenters said this 

enforcement discretion approach has provided prompt, flexible 

relief that is tailored to the needs of the particular emergency 

and the communities being served, yet is only utilized where the 

relief will address the particular emergency at hand. Commenters 

added this enforcement discretion approach is consistent with 

CAA’s mandate that emission limits apply continuously and 
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provide safeguards against abuse. One commenter stated that the 

emergencies that the EPA mentions happen rarely and typically 

last for short periods, and the proposed applicability threshold 

would allow a source to operate at its full rated capacity for 

up to 2,920 hours per year without triggering NSPS, and the 

potential occurrence of grid emergencies represents 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 – can 

justify operating a peaking unit above a 10 percent capacity 

factor on a 3-year rolling average. 

3. Final Applicability

For the final rule, we are retaining the applicability 

criteria that the unit must be capable of combusting more than 

250 MMBtu/h heat input of fossil fuel, and must serve a 

generator capable of selling more than 25 MW to the grid. While 

some commenters suggested we should cover smaller EGUs as well, 

we did not propose to cover smaller units. Considering this, 

that smaller sources emit relatively few CO2 emissions compared 

to larger units, and that at this time we do not have 

information to identify an appropriate BSER for these units we 

are not finalizing any CO2 standards for smaller units. However, 

based on consideration of the comments received related to the 

other four proposed applicability criteria and practical 
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implementation issues, we are revising how those criteria will 

be implemented. First, the proposed actual electric sales 

relative to the potential electric output and the actual percent 

natural gas usage criteria are being finalized as applicability

criteria based on operating restriction included in a federally 

enforceable permit. Second, for non-CHP combustion turbines we 

are eliminating the proposed 219,000 MWh electric sales 

criterion. Next, the proposed 10 percent fossil fuel use 

applicability criteria is being finalized as an exemption for 

non-fossil fuel-fired units that are subject to a federally 

enforceable permit condition limiting the use of fossil fuel. 

Finally, similar to the proposed actual electric sales criteria, 

the proposed constructed for the purpose of selling one-third of 

your potential electric output applicability criteria is being 

finalized as an exemption for dedicated peaking units that are 

subject to a federally enforceable permit limiting annual 

electric sales. Section III described the rationale for why the 

EPA is not finalizing GHG standards for dedicated non-fossil 

fuel-fired or industrial CHP combustion turbines. The final 

applicability is generally consistent with the broad 

applicability approach we solicited comment on.

The EPA agrees with commenters that the NSPS applicability 

framework should be structured so that permitting authorities 

and the regulated community can determine what standards apply 
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prior to a facility having commenced construction. Therefore, 

the EPA has concluded that the proposed retrospective 

applicability criteria for combustion turbines that included 

actual electric sales and the amount of natural gas combusted 

are not practical approaches, since applicability determinations 

verse these criteria could change from year to year (i.e., 

facilities could be moving in and out of applicability each 

year). Furthermore, from a practical implementation standpoint,

existing permitting rules would generally require preconstruction permitting authorities to include enforceable 

conditions limiting operations such that unaffected units would 

not trigger either the proposed electric sales or fuel use 

thresholds if they were included as general applicability 

criteria. Such conditions are often called “avoidance” or 

“synthetic minor” conditions, and these conditions typically 

include ongoing monitoring, recordkeeping, and reporting 

requirements to ensure operations remain below a particular 

regulatory threshold. 

The EPA evaluated several approaches for implementing the 

proposed retrospective applicability criteria through a preconstruction and operating permit program. For the proposed 90 

percent natural gas fuel use criterion, the EPA has concluded 

that a comparable permit restriction would be to exempt all 

facilities not subject to an operating permit restriction 
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requiring that natural gas contribute over 90 percent of the 

heat input. This is not a practical restriction since (1) 

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) and 

not to limit lower emitting activities; (2) new combustion 

turbines could avoid applicability by simple not having a permit 

that requires the use of over 90 percent natural gas even if 

they intend to only burn natural gas; and (3) this approach is 

inconsistent with the objectives under CAA section 111(d) and 

would essentially provide a pathway for all combustion turbines 

to avoid applicability under state 111(d) plans. Similarly, 

finalizing an applicability requirement that exempts combustion 

turbines unless they have a permit restriction limiting nonnatural gas to 10 percent or less of the heat input (i.e., limit 

the use of natural gas to less than 90 percent of the total heat 

input) is also problematic. Owners/operators of new combustion 

turbines could avoid applicability by simply being permitted to 

burn non-natural gas fuels for over 876 hours per year even if 

they actually intended to seldom, if ever, combust the alternate 

fuels. Many commenters expressed the need to maintain the 

ability to burn distillate oil, particularly during natural gas 

curtailments. Consequently, this approach would cause similar 

applicability issues for both 111(b) and 111(d). The EPA has 
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concluded that the only way to distinguish a non-natural gasfired combustion turbine and a natural gas-fired combustion 

turbine is the ability to burn any natural gas. Consistent with 

the intent of the rule (to establish GHG emission standards for 

natural gas-fired combustion turbines) we are not finalizing GHG 

standards for combustion turbines that are not capable of firing 

any natural gas. Combustion turbines without any connection to a 

natural gas pipeline would not be subject to any of the 

requirements of this rulemaking. 

For the proposed one-third electric sales criterion, the 

EPA has concluded that a comparable permit restriction would be 

to require a combustion turbine to actually sell more 

electricity than the specified threshold. Similar to the fuel 

use requirement, this is impractical because new combustion 

turbines could avoid applicability by simply not having a permit 

restriction to actually sell more than one-third of its 

potential electric output. Even if a facility were subject to 

this restriction, a permit violation for a unit that does not 

operate enough to sell one-third of its potential electric 

output is nonsensical since system demand may not be sufficient 

to allow all permitted units to operate above the specified 

threshold. The EPA has concluded that a permit restriction 

similar to the proposed one-third electric sales criterion would 

restrict sales to less than one-third of the potential electric 
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output. Combustion turbines not subject to a federally 

enforceable electric sales restriction would have to comply with 

the applicable standards. The EPA has concluded this approach is 

appropriate for identifying dedicated peaking units. To 

determine an appropriate annual electric sales threshold to 

subcategorize dedicated peaking units, the EPA reviewed 

operating data for existing simple cycle units from 2005 to 

2014. The EPA has concluded that an appropriate annual electric 

sales threshold for dedicated peaking units should be high

enough to include how the majority of simple cycle turbines have 

historically operated. We have concluded that based on the 

revised electric sales applicability criteria and practical 

implementation issues (i.e., operating permit restrictions are 

written on an annual basis) permit restrictions for NSPS 

applicability purpose will be annual limits, as opposed to the

proposed 3 year actual net electric sales applicability 

criteria.

As stated earlier, we have concluded it is appropriate to 

avoid perverse impacts resulting from the applicability of this 

rulemaking. If we set an electric sales applicability permit 

restriction threshold too low it could have the unintended 

impact of increasing GHG emissions. Utilities have an obligation 

to provide sufficient electricity to meet system demand 

regardless of specific emission standards that have been placed 
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on individual units. By limiting certain units to less than onethird of their potential electric output, utilities and other 

developers could justify building multiple lower capital cost, 

but less efficient, simple cycle turbines combustion turbines 

subject to avoidance limits below the electric sales threshold 

compared to fewer higher capital cost more efficient simple 

cycle combustion turbines that could meet the same demand by 

operating just above the proposed threshold. In either case, 

system demand would be the same and a sufficient numbers of 

combustion turbines would be built to assure sufficient 

generation capacity was available, but the associated GHG 

emissions and the cost to ratepayers would be higher for the 

scenario with multiple turbines operating at lower loads than 

the fewer more efficient units. In contrast, setting an electric 

sales applicability threshold that is too high could leave new 

units with a substantial amount of potential CO2 emissions 

unregulated and would reduce the number of units included in 

111(d) state plans. In addition, developers of new EGUs 

completely exempt from the 111(b) would also have a perceived 

benefit of not being subject to potential future revisions of 

111(d) requirements. In balancing these competing factors, the 

EPA has concluded that a permit restriction tied to the design 

efficiency of the unit is appropriate (i.e, the sliding scale 

approach). Specifically, owners/operators of new units subject 
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to a permit restriction limiting annual net electric sales to 

the design efficiency of the unit times the potential electric 

output (e.g., limiting annual hours of operation to the design 

efficiency times 8,760 hours) would not be subject to the final 

requirements of this rulemaking. For a more detailed discussion, 

see the BSER discussion.

The EPA has concluded concerns raised during the public 

comment period suggesting that the 219,000 MWh annual sales 

exemption would encourage the installation of multiple smaller, 

less efficient simple cycle combustion turbines instead of a 

single, more efficient and larger turbine are valid. The 219,000 

MWh electric sales criterion allows simple cycle combustion 

turbines (e.g., less than 80 MW) to sell significantly more 

electricity relative to the potential electric output than 

larger turbines. Many commenters expressed that there is an 

inherent value in flexibility to operate simple cycle turbines 

at high capacity factors even if it is never intended to run at 

a high capacity factor. One of these factors is the ability to 

get capacity payments from the transmission authority. If we 

finalized the 219,000 MWh electric sales criterion for 

combustion turbines we would be providing a perverse incentive 

to install smaller, less efficient simple cycle turbines. We are 

therefore not finalizing the 219,000 MWh annual electric sales 

exemption for non-CHP combustion turbines. 
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We have concluded that the emergency conditions exemption 

provides flexibility to maintain system reliability and 

minimizes overall costs to the sector. Therefore, we are 

finalizing that electricity sold during hours of operation when 

the unit is called upon to operate due to a system emergency 

will not be counted as net electric sales. Electric sales from 

units that are not called upon to operate specifically due to 

the system emergency (e.g., already operating when the system 

emergency is declared) would be treated as normal net electric 

sales.

B. Identification of the Best System of Emission Reduction

This section summarizes the proposed BSER for combustion 

turbines, provides a summary of comments received, and the final 

BSER determination. For combustion turbines, we proposed and are 

finalizing the use of combined cycle technology as the BSER for 

affected stationary combustion turbines. Combustion turbines

would be required to meet an output based emission standard 

based on what we have concluded is an achievable standard based 

on review of emission rate information from existing natural 

gas-fired combined cycle units and permitted emission standards 

for recent natural gas-fired combined cycle units.

1. Proposed BSER

At proposal, we considered three alternatives in evaluating 

the BSER for new natural gas-fired stationary combustion 
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turbines (1) high efficiency simple cycle aeroderivative 

turbines (2) modern, efficient NGCC units, and (3) CCS. We 

rejected high-efficiency simple cycle aeroderivative turbines as 

the BSER because this standalone technology does not provide 

emission reductions and is more expensive compared to combined 

cycle technology. We rejected NGCC with CCS as the BSER because 

we concluded that at proposal we had insufficient information to 

make a determination regarding the technical feasibility of 

implementing CCS at combustion turbine units. In contrast, 

combined cycle units are the most common type of new fossil 

fuel-fired units being planned and built today for generating 

intermediate and base load power. The design is technically 

feasible and combined cycle units are currently the lowest-cost, 

most efficient option for new fossil fuel-fired power 

generation. After considering the technology options, the EPA 

proposed to find modern, efficient NGCC technology to be the 

BSER for stationary combustion turbines, and we based the 

proposed standards on the performance of recently constructed 

natural gas-fired combined cycle units. 

2. Comments

Many commenters opposed the grouping of simple cycle units 

and combined cycle units in the same category and establishing 

the BSER for combustion turbines strictly based on the combined 

cycle mode of operation. Commenters pointed to the word 
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"achievable" in CAA section 111(a)(1) and stated that applying 

an emission standard based on combined cycle technology to 

simple cycle units is legally indefensible because simple cycle 

units cannot achieve emission rates as low as combined cycle 

units. Commenters also stated that under CAA section 111(b)(2) 

the EPA may acknowledge these different functions by completing 

function-specific BSER determinations and by establishing 

separate standards for these functions. Many commenters stated 

that combined cycle technology should be the BSER for base-load 

and intermediate-load functions, while simple cycle should be 

the BSER for peak-load functions.

Some commenters stated that the proposed BSER analysis for 

coal-fired units was inconsistent with the BSER analysis for 

natural gas-fired combustion turbines. They stated the EPA 

determined that use of CCS is feasible for coal-fired generation 

based on current CCS projects under development at coal-fired 

generating stations, but the agency did not come to the same 

conclusion for natural gas-fired combustion turbines when there 

is an NGCC project under development that will apply CCS to a 

slip stream of NGCC flue gas. Commenters further stated that it 

is irrelevant that the NGCC CCS project is a partial CCS project 

whereas the developmental projects for coal fired units are 

"full-scale." These commenters stated that the EPA cannot 

utilize projects under development as a basis for justifying CCS 
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as BSER for coal fired units and then abandon this basis for 

NGCC units. In addition, some commenters disagreed with the 

EPA’s decision to treat NGCC differently than coal-fired units 

on the basis that NGCC units start up and shut down more 

frequently than coal-fired units. The commenter said operating 

characteristics of NGCC units are not an impediment to using 

partial CCS, and suggested that NGCC operators could bypass the 

carbon capture system during startup and shutdown modes (which 

are typically shorter and less intensive efforts compared to 

startup or shutdown of a coal facility) and then employ the 

carbon capture system when operating normally. Many commenters 

stated that CO2 removal is just as technologically feasible and 

economically reasonable for an NGCC EGU as a coal-fired EGU. 

These commenters referred to literature suggesting that at 40 

percent removal there would be no expected difference in the 

technical requirements for either type of EGU. Some commenters 

referred to a DOE/NETL study that suggests the cost of CCS for 

NGCC is more cost effective than for coal-fired EGUs. 

Many commenters supported the EPA’s determination that NGCC 

with CCS technology is not BSER for newly constructed, modified, 

or reconstructed combustion turbines. These commenters agreed 

that there are insufficient data on costs and site-specific 

constraints to conclude that CCS and EOR technologies are 

available and feasible at the numerous locations in the U.S. 
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where combined cycle projects are currently planned based on 

projected natural gas prices. Commenters stated that the limited 

scope of the one CCS-on-NGCC project cited in the proposal did 

not reflect the costs of pipeline transport and geologic 

sequestration implicit in use of this technology as a nationwide BSER technology because the slip stream of CO2 is used at a 

local facility that temporarily incorporates the CO2 into food 

products. Commenters also stated that CCS has not been 

adequately demonstrated or proven to be commercially viable for 

NGCC units. Other commenters stated that CO2 capture technologies 

do not match well with the operating flexibilities of NGCC and 

simple cycle units, and even if technical barriers could be 

overcome, application of CCS to gas-fired turbines would also be 

more costly (compared to applications of CCS to coal-fired 

units) on a dollars-per-ton-CO2-captured basis because of the 

higher flue gas volumes (per MW of generating capacity) and the 

lower CO2 concentrations from methane combustion in turbines 

compared to coal combustion in boilers.

Some commenters stated that a CCS-based standard for NGCC 

units would negatively impact the environment and the nation’s 

energy needs. They also stated that CAA section 111(a) requires 

the EPA to account not only for the cost of achieving emission 

reductions, but also for the impact of BSER on energy 

requirements and the environment. The commenters cited Costle, 
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where the D.C. Circuit observed that, following its analysis of 

adequately demonstrated emissions technology, the EPA "must 

exercise its discretion to choose an achievable emission level 

which represents the best balance of economic, environmental, 

and energy considerations."402 The commenters also stated that 

requiring CCS on natural gas units would adversely affect the 

nation’s energy needs and the environment because imposing 

partial CCS on natural gas-fired combustion turbines would 

invariably delay the emission reductions that can be obtained 

from new NGCC projects that displace load from older less 

efficient generating technologies. Finally, the commenters 

stated that since NGCC units are projected to provide a 

significant share of new power generation, the EPA should 

recognize that requiring partial CCS on NGCC units would have 

proportionally higher impact on electricity prices compared to 

the projected number of new coal-fired generating projects. 

These commenters concluded that the EPA cannot determine that 

partial CCS is BSER for NGCC units without producing severe and 

unacceptable consequences for the availability of affordable 

electricity in the United States. In a related comment, another 

commenter said that CCS is technically feasible for gas turbine 

facilities, but agrees that requiring CCS for all new NGCC 

 

402 Costle, 657 F.2d at 431, n. 46.
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plants may hinder the construction of new, more efficient NGCC. 

Instead, the commenter suggested the EPA defer a decision on 

whether CCS is BSER for combustion turbine units until the 

subsequent NSPS revisions. The commenter expressed concerns that 

the EPA’s rationale for rejecting CCS as BSER for NGCC, may be 

used by developers and permitting authorities as an excuse to 

reject CCS as Best Available Control Technology (BACT) in future 

New Source Review (NSR) permits.

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. These commenters stated that advanced 

NGCC technologies are capable of achieving emission rates that 

are 8 percent lower than conventional NGCC facilities. 

Commenters said that the majority of existing sources that do 

not deploy these advanced technologies are currently able to 

meet the standard, and commenters said that the proposal failed 

to explain why these lower-emitting advanced technologies that 

are more than adequately demonstrated were not selected as the 

BSER.

3. Identification of BSER
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As stated in the proposal, combined cycle units have both 

lower GHG emissions and a lower cost of electricity than simple 

cycle turbine facilities when operated as intermediate and base 

load EGUs. Therefore, the use of a combined cycle technology 

would be BSER for higher capacity factor stationary combustion 

turbines. The EPA refined the LCOE costing approach used at 

proposal to compare the cost effectiveness of simple cycle 

combustion turbines compared to combined cycle combustion 

turbines by adding costs and efficiency impacts due to frequent 

cycling. Even accounting for these costs, combined cycle 

technology results in a lower cost of electricity, compared to a 

simple cycle unit, when electric sales exceed one-third of the 

potential electric output. Furthermore, we have concluded that 

high efficiency simple cycle turbine technology is a subcomponent of the selected BSER. Recent combined cycle 

installations have included dampers that allow the associated 

combustion turbine to operate in either combined cycle mode or 

simple cycle mode. The selected BSER and emission standard is 

compatible with the construction of new, modified, and 

reconstructed bi-modal units with dampers that allow the new 

source to operate in either combined cycle mode or in simple 

cycle mode; therefore the use of combined cycle technology is 

BSER for periods of intermediate and base load operation. 
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However, for dedicated peaking applications highly efficient 

simple cycle technology alone is considered the BSER. 

The EPA has reviewed the comments on the use of CCS for 

combined cycle facilities and has concluded that even if CCS is 

demonstrated as a technical and reasonable cost option for 

combined cycle units on an individual basis, it would not 

qualify as BSER based on the nationwide economic impacts. 

Therefore, the EPA is not making a determination as to the 

technical availability or individual cost reasonableness of CCS 

for new combined cycle units. Nearly all new fossil fuel-fired 

EGUs being constructed today are using combined cycle technology 

for generating intermediate and base load power and requiring 

partial CCS on these units would result in unreasonable

nationwide impacts. 

The EPA has concluded that advanced combined cycle 

technology is simply incremental improvements to traditional 

combined cycle designs and not a unique technology and therefore 

cannot be the BSER. The emission rates achieved by these 

technologies were included within the data set of newer combined 

cycle designs used for establishing the standard. In addition, 

review of the operating data for combined cycle power blocks 

installed since 2000 indicates that the mode of operation in 

response to system demand (e.g., base load or intermediate load 

and capacity factor in general) impacts achieved efficiencies to 
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a large enough extent that we cannot evaluate the impact of 

particular subcomponents used within the power block. So a 

conventional combined cycle power block located in a region of 

the country where system demand requires the power block to run 

continuously at base load can achieve higher efficiencies than 

an advanced combined cycle 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 combined cycle power blocks can achieve the section 111 

standard in all regions of the country. 

4. Identification of Applicability Based on Permitted Electric 

Sales

At proposal, we assumed all combustion turbines operating 

above the proposed 1/3 electric sales criterion would be able to 

comply with a standard consistent with the performance of 

recently constructed combined cycle facilities. However, as 

described in the applicability section, our understanding of the 

future role of combustion turbine EGUs has evolved. At this time 

however, we do not have sufficient information to establish an 

appropriate output-based emission rate for combustion turbines 

operating with operations that span this entire category. 

Therefore, our applicability approach is to use a sliding scale 

trigger. With the sliding scale approach, the trigger for 
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applicability for the combined cycle standard depends on the 

design efficiency of the unit. Affected units subject to 

federally enforceable permit restrictions limiting operating 

below the electric sales threshold would not be required to 

comply with the requirements included in subpart TTTT. This both

encourages the installation of the most efficient technologies 

intended for limited operation by giving the most efficient 

units the flexibility to sell more electricity and minimizes 

emissions for higher capacity factor units by requiring them to 

comply with the requirements of subpart TTTT. 

As discussed previously, the proposed percent actual 

electric sales relative to the potential electric output 

criterion is being finalized as a permit restriction

applicability criteria. Based on the concerns raised in the 

comments about the impact of intermittent renewable generation 

(e.g., wind and solar) on the operation of simple cycle 

turbines, the EPA has done additional analysis. First, we 

evaluated the percent sales applicability criterion in greater 

detail to get a more accurate picture of how many simple cycles 

would have met the electric sales applicability criterion based 

on historical operation. We also examined the operation of 

simple turbines in regions with relatively large amounts of wind 

and solar generation. 
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In the proposal, the EPA estimated the number of simple 

cycle turbines that would have met the proposed applicability 

based on the number of simple cycle turbines that operated over 

2,920 hours in any year. However, this was a simplification of 

the one-third actual electric sales criteria and overestimated 

the number of potentially impacted simple cycle turbines in two 

ways. First, the 2,920 hours simplification assumes operation at 

full load. However, the typical duty cycle (average capacity 

factor while operating) of simple cycle turbines is 

approximately 70 percent. Therefore, simple cycle turbines can 

operate in excess of 2,920 hours and still not be selling onethird of their potential electric output. Historically, only 10 

of the 1,939 existing simple cycle turbines have individual 

years where sales exceeded one-third of their potential electric 

output. Second, the proposed one-third electric sales 

applicability criterion was on a 3-year rolling average basis. 

Using 3-year rolling average basis, the number of existing 

simple cycle turbines that historically sold enough electricity 

to meet the proposed one-third electric sales applicability is 

only two. 

We used information reported to the Energy Information 

Administration (EIA) to determine the impact of renewable 

generation on the operation of simple cycle turbines. The EIA 

provides data on the total in-state electricity generation, 
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including wind and solar, from 2008 through 2014. Interstate 

flow of electricity is available from 2008 through 2012. 

California, Texas, and the Southwest Power Pool (data 

approximated by EGUs in Nebraska, Kansas, and Oklahoma) all had 

increases for the percent of wind and solar electricity 

generated in-state and percent of total electric generation from 

wind and solar from 2008 through 2014. To determine the observed

impact of the increased generation from intermittent renewable 

sources, the EPA reviewed data submitted for simple cycle 

turbines to the EPA’s Clean Air Markets Division (CAMD) over the 

same time period.

The percent 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 would expect to see a large change in the operation 

of simple cycle turbines in this region. However, the average 

percent electric sales compared to the potential electric output 

from simple cycle turbines only increased at an annual rate of 

1.7 percent, and remained essentially unchanged at 3 percent of 

potential electric sales between 2008 and 2014. Overall, 

generation from simple cycle turbines increased slightly more at 

an annual rate of 2.5 percent, resulting from additional simple 
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cycle capacity being in line with what was expected due to 

overall increased electricity demand. The lack of significant 

change in the operation of simple cycle turbines in this region 

could be explained by the relatively large amount of exported 

power. If most of the intermittent power was being exported, the 

intermittent nature of the power would primarily impact other 

transmission regions. An alternate explanation is that other 

generating assets are flexible enough to respond to the 

intermittent nature of wind generation and that simple cycle 

turbines are not necessary to backup wind and solar generating 

assets to the degree some commenters suggested. If this were the 

case, then new simple cycle turbine will primarily continue to 

fill their historical role as peaking units and flexible 

combined cycle units will provide the primary backup capacity 

for new wind and solar generating assets.

The percent 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 the 

overall demand grew an average of 2 percent annually. However, 

similar to the Southwest Power Pool, the overall percent of 

electric sales relative to the potential electric output from

simple cycle turbines has remained relatively unchanged. Average 

electric sales relative to potential electric output from simple 

cycle turbines increased at an annual rate of 0.9 percent. 
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However, the overall generation from simple cycle combustion 

turbines increased at an annual rate of 6.6 percent, resulting 

from simple cycle capacity additions occurring at approximately 

four times what would be expected from growth in overall demand. 

The EPA has concluded that the most likely simple cycle turbines 

to support intermittent renewable generation are the most 

efficient simple cycle combustion turbines installed in the 

particular transmission region. 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 sales annually. This growth in simple cycle turbine 

capacity could indicate that additional generation assets are 

necessary to provide firm capacity for intermittent generation 

sources such as wind and solar, but based on the data those 

simple cycle turbines are expected to continue operating as they 

have historically, and sell less than one-third of their 

potential electric output. 

The percent 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 
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cycle turbines in California has changed more significantly than 

the other evaluated regions. As in Texas, considerable 

additional simple cycle capacity has been added in recent years. 

The average 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. Many of the new additions are 

intercooled simple cycle turbines that can be installed to back 

up wind and solar generation. The annual electric sales relative 

to the potential electric output for the intercooled turbines 

range 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.

Based on historical amounts of intermittent generation, the 

proposed one-third actual electric sales threshold would appear 

to offer sufficient operational flexibility for new simple cycle 

turbines. Existing combined cycle, other generation assets, and 

demand response programs are currently proving adequate backup 

to renewable generation. In the future, however, existing 

combined cycle facilities will likely provide base load power 

and operate at higher capacity factors. They will therefore be 

less available to provide backup power for intermittent 

generation. In addition, the percent of power generated from 
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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. Even 

though fast start combined cycle technologies, reciprocating 

internal combustion engines, energy storage technologies, and 

demand response 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 necessary capacity 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 GHG benefits of these 

technologies compared to simple cycle turbines, the EPA has 

concluded at this time it is appropriate to finalize an NSPS 

that provides additional flexibility for new combustion turbines

intended to run at lower capacity factors. Specifically, new 

combustion turbines can avoid the requirements of subpart TTTT 

by requesting a federally enforceable permit restriction to sell 

the design efficiency times the potential electric output

electricity on an annual basis. 

The EPA considered multiple options for extending 

flexibility for simple cycle turbines. Ultimately, we concluded 

that a trigger based on the design net efficiency at standard 

conditions is appropriate. The electric sales trigger for 
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applicability of the combined cycle based standard would be 

based on the design net efficiency of the facility. The EPA has 

concluded this approach provides sufficient operational 

flexibility for new simple cycle combustion turbines, even with 

increased future use. In addition, even though the historical 

electric sales of simple cycle turbines is less than 5 percent, 

this net efficiency trigger approach has the impact of promoting 

the installation of the most efficient generating technologies

since applicability and operational flexibility would be linked 

directly to the efficiency of the devices. The design net 

efficiencies for currently available potentially impacted 

aeroderivative simple cycle combustion turbines range from 

approximately 32 percent for smaller designs to 39 percent for 

the largest intercooled designs. The efficiencies of industrial 

frame units range from 30 percent for smaller designs to 36 

percent for the largest units. 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 United States 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 higher heating value. For natural gas, the LHV is 

approximately 10 percent lower that the HHV. Therefore, the 
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corresponding LHV efficiency ranges would be 35 to 44 percent 

for aeroderative designs and 33 to 40 percent for frame designs.

Based on comments, we anticipate the aeroderative turbines will 

make up the majority of new combustion turbines intended for 

limited use (i.e., peaking) applications. Based on the sliding 

scale applicability approach, owners/operators of new simple 

cycle combustion turbines could elect to request a federally 

enforceable permit limiting annual sales to between 32 to 39 

percent of the potential electric output to avoid complying with 

the standards in this rulemkaing. Based on historical operation 

of simple cycle turbines, 99.5 percent do not sell more than 

one-third of their potential electric output on an annual basis. 

Therefore, the majority of new simple cycle applications could 

take a permit restriction without impacting how they would 

operate or what combustion turbine they would select. In 

addition, 99.9 percent of simple cycle turbines operate less 

than 36 percent on an annual basis. Owners/operators of new 

simple cycle combustion turbines would still have multiple 

technology options available to them to accommodate this amount 

of operation. The two simple cycle turbines that exceeded the 36 

percent threshold had annual sales of 39 and 45 percent and are 

located in Montana and New York respectively. As noted earlier, 

the most efficient simple cycle turbine is 39 percent efficient 

and would accommodate operation of the Montana facility. The 
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only simple cycle turbine that exceeded the maximum electric 

threshold permit restriction, 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 and the incremental generation due to the emergency 

would not have been counted as net electric sales for 

applicability purposes. Regardless, as described earlier, for 

combustion turbines operating above this threshold it is cost 

effective and the BSER is the additional of heat recovery to the 

turbine exhaust. Since the definition of stationary combustion 

turbine includes both simple and combined cycle units, we are 

capping the maximum permit restriction to 40 percent of the 

potential electric output. Combined cycle unit design 

efficiencies often exceed 50 percent. Without this restriction 

many existing combined cycle units could request permit 

limitations to avoid applicability with the 111(d) requirements. 

C. Achievability of the Final Standards

We concluded at proposal that, for a combustion turbine 

designed to sell greater than one-third of its potential 

electric output, adding heat recovery and converting to a 

combined cycle is both cost effective (i.e., results in a lower 

cost of electricity) and results in a lower emission rate. The 

proposed standards of performance for natural gas-fired 

stationary combustion turbines were in the form of a gross-
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output-based emission limit expressed in units of mass of CO2 per 

unit of gross energy output, specifically, in lb CO2/MWh-gross. 

The subcategories for which the EPA proposed separate standards 

of performance were (1) large natural gas-fired stationary 

combustion turbines with a base load rating greater than 850 

MMBtu/h403 and (2) small natural gas-fired stationary combustion 

turbines with a base load rating less than or equal to 850 

MMBtu/h. The EPA solicited comment on a broad range of issues 

related to the final standard. For new, modified, and 

reconstructed units we proposed a limit of 1,000 lb CO2/MWh-gross

for large units (base load heat input rating greater than 850 

MMBtu/h) and 1,100 lb CO2/MWh-gross for small units (base load 

heat input rating of 850 MMBtu/h or less). We solicited comment 

on a range of 950 – 1,100 lb CO2/MWh for large stationary 

combustion turbines and an emission standard range of 1,000 –

1,200 lb CO2/MWh for small stationary combustion turbines. We 

also solicited comment on eliminating the size subcategory,

increasing the size distinction between large and small 

stationary combustion turbines to 900 MMBtu/h to account for 

larger aeroderivative designs, to 1,000 MMBtu/h to account for 

 

403 This subcategorization of stationary combustion turbines is 

consistent with the subcategories used in the combustion turbine 

(subpart KKKK) criteria pollutant NSPS. The size limit of 850 

MMBtu/h corresponds to approximately 100 MWe. Based on the 

largest aeroderivative turbine design available when subpart 

KKKK originally promulgated
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future incremental increases in base load ratings, or on 

increasing the size distinction to between 1,300 to 1,800 

MMBtu/h. In addition, we solicited comment on establishing a 

variable capacity factor threshold that would allow more 

efficient, lower emitting turbines to run and be permitted for 

longer periods of operation (e.g., a higher capacity factor for 

the most efficient turbines being progressively lowered for 

lower efficiency turbines). 

With respect to the size subcategory, some commenters and 

others agreed with the 850 MMBtu/h break point between large and 

small units, some suggested increasing it to 1,500 MMBtu/h, and 

others suggested eliminating the size based subcategorization.

Some commenters stated that the current 850 MMBtu/h size 

distinction is inappropriate for CO2 because it was originally 

determined based on NOX performance and not significant for CO2

emission rates. These commenters stated that the 850 MMBtu/h 

cut-point, when compared to the existing fleet, does not result 

in a logical cut-point with a clear demarcation of higher 

emitting versus lower emitting technology on either side of this 

value, but rather divides the units at an arbitrary size 

classification. These commenters suggested 1,500 MMBtu/h since 

there is a clear cut-point in the existing fleet of gas turbines 

between the heat input range of 1,300 MMBtu/h and 1,800 MMBtu/h, 
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with more efficient and lower CO2 emitting technology above and 

below 1,500 MMBtu/h. 

In contrast, other commenters said that differentiation of 

small and large gas turbines cannot be justified because many of 

the same technologies that reduce the emission rates of larger 

units could be incorporated into smaller units. Commenters also 

said that separate standards for small and large turbines 

undermine the incentive for technology innovation, a key purpose 

of the NSPS program, and that relaxing standards for smaller 

units will discourage investment in more efficient technologies. 

These commenters recommended that the limit for both large and 

small units be no higher than 1,000 lb CO2/MWh. Finally, some 

commenters suggested that the EPA should regulate multiple small 

units built together as a single large unit if the combined heat 

input capacity of all gas turbines at the facility exceeds 

850 MMBtu/h. 

Numerous commenters from the power sector, air permitting 

authorities, and environmental groups acknowledged that 

accelerating renewable portfolio standards in certain states

coupled with NERC reliability requirements can affect the 

performance of combined cycle natural gas EGUs as they are 

increasingly cycled and operated at lower capacity factors to 

complement hourly variations in intermittent renewable 

generation (e.g., solar and wind). However, commenters had a 
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wide range of opinions on the extent to which intermittent 

renewables should be used to justify increasing the national 

emissions standard above the emission rate that can be achieved 

by well-operated and maintained intermediate and base-loaded 

combined cycle plants. 

Commenters from the power sector generally supported 

increasing the standard for each subcategory to 1,100 lb CO2/MWhgross for large units and 1,200 lb CO2/MWh-gross for small units

and finalizing standards for modified and reconstructed 

standards that are 10 percent higher than the final standards 

for newly constructed combustion turbines because combustion 

turbines constructed prior to 2000 were not included in the 

EPA's BSER analysis for new sources. 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, and these commenters do not believe 

the proposed numerical standards meet the CAA section 111 

requirements for BSER. Some commenters stated that the 

appropriate limitation, consistent with Congressional objectives 

under CAA section 111, is 800 lb CO2/MWh-gross based on the 

performance of the lowest emitters in the CAMD database. Some 

commenters stated that a limitation of 850 lb CO2/MWh-gross 

reflected BSER for high-capacity factor units because half of 

the combined cycle plants in the CAMD database are achieving 
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this level of emissions. One commenter from the power sector who 

operates combined cycle power plants stated that the final 

standard for new large combustion turbines should be 925 lb 

CO2/MWh-gross. Several other commenters stated that a reasonable 

standard for new combustion turbines would be 950 lb CO2/MWhgross, and several commenters stated that the final standard for 

new small combustion turbines should be 1000 lb CO2/MWh-gross. 

Numerous commenters stated that the final standard for new 

sources should not exceed 1,000 lb CO2/MWh-gross for either large 

or small combustion turbines. Other commenters stated that since 

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. These commenters stated that since 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.

Numerous commenters supported tiered subcategories for 

peaking, load-following/intermediate, and base load units. 

Commenters noted that the EPA’s proposals excluded units that 

operate in peaking mode and argued there is no basis in law or 

policy to exempt units from regulation simply because they 

operate less frequently, and hence less efficiently. Commenters 

said the EPA should cover all sources that supply (or are 
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designed to supply) any amount of electricity to the grid, and 

should distinguish subcategories based on actual operation.

Several commenters supported tiered standards based on capacity 

factor. They proposed 825 lb CO2/MWh-gross for base load units 

(those operating over 4,000 hours annually), 875 lb CO2/MWh-gross 

for intermediate and load-following units (those operating 

between 1,200 and 4,000 hours annually), and 1,100 lb CO2/MWhgross for peaking units (those operating less than 1,200 hours 

per year). One of the most common comments received was that 

peaking units should be either included in a subcategory or 

completely exempted due to the highly variable capacity factors 

and duty cycles imposed by system operators on these versatile 

generators. Numerous commenters pointed to recent BACT limits 

for CO2 that indicate tiered limits are appropriate for the 

different roles served by combustion turbines citing BACT limits 

from 1,328 to 1,450 lb CO2/MWh-gross for peaking units. One 

commenter supported tiered limits consistent with recent BACT 

determinations in the State of New York: a combined cycle limit 

of 925 lb CO2/MWh-gross and a simple cycle limit of 1,450 lb 

CO2/MWh-gross. An air quality regulator from a state with rapidly 

increasing renewable generation supported a limit of 825 lb 

CO2/MWh-gross for base load NGCC units; 1,000 lb CO2/MWh-gross 

for intermediately loaded, large NGCC units; 1,100 lb CO2/MWhgross for intermediately loaded, small NGCC units; and this 
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commenter recommended that the EPA set a numerical limit 

specifically for peaking units after completion of a peakerspecific BSER analysis. 

Other commenters opposed the tiered approach. Commenters 

suggested that separate standards for different operating 

conditions would be complicated to implement and enforce, 

provide few benefits, and could have the unintended consequence 

of encouraging less efficient technologies and less efficient 

operation. Commenters added that annual capacity factors would 

likely vary significantly from year to year, and possibly from 

month to month as the 12 operating month average is recalculated 

every operating month. The commenters stated that this realworld variability and uncertainty significantly diminishes the 

value of creating tiered standards for peaking and loadfollowing units because individuals responsible for long-range 

decisions related to reliability may react to a system of tiered 

standards by purchasing additional generating assets to ensure 

system demand can be satisfied while operating individual units 

below tier-specific thresholds.

After further evaluation, the EPA has concluded against 

subcategorizing the combustion turbine standard based on size 

for several reasons. While some commenters suggested that the 

division between large and small should be increased to 1,500 

MMBtu/h, other commenters said subcategorizing based on size 
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would distort the market and provide a regulatory incentive to 

install less efficient, smaller combined cycle facilities, 

resulting in increased GHG emissions. The EPA reviewed data on 

the size of available combined cycle facilities (without duct 

burners) listed in Gas Turbine World. Combined cycle turbines 

are not currently offered in the following output sizes: between 

600 to 800 MMBtu/h, 1,000 to 1,200 MMBtu/h, and 1,300 to 1,800 

MMBtu/h based on the heat input to the combustion turbine

engine. However, a review of heat input data by the EPA for 

combined cycle facilities submitted to the EPA Clean Air Markets 

Division show that multiple combined cycle facilities have been 

built in the past with heat input capacities with the capacities

listed above. Therefore, the EPA has concluded that the 

regulated community uses various sizes of combined cycle 

facilities and that no clear cut point distinguishes small and 

large combined cycle facilities. Subcategorizing by size could 

unduly influence the selection of technology and development of 

future turbine offerings. Further, the average emissions rate of 

combined cycle facilities of less than 850 MMBtu/h (the proposed 

cut point) is lower than the average emissions rate of combined 

cycle facilities with heat input ratings of 850 MMBtu/h up to 

1,500 MMBtu/h. Finally, the EPA has concluded that, while 

certain smaller combined cycle designs are less efficient than 

larger combined cycle designs, this is primarily related to 
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design choices of the heat recovery steam generator, and is not 

an inherent limitation in the technical ability of small 

combined cycle technologies to have comparable efficiencies to 

large combined cycle facilities.

Since the standards were proposed, the EPA has expanded the 

NGCC emissions rate analysis that supported the proposed 

emission standards to include emissions information for combined 

cycle facilities that commenced operation in 2011, 2012, and 

2013 and updated the emissions data to include emissions through 

2014. Based on analysis of these data and the comments submitted 

on the proposed standard, the EPA has concluded that an emission 

standard of 1,000 lb CO2/MWh-gross is achievable for all affected 

combustion turbines. Therefore, the EPA is finalizing an 

emission standard of 1,000 lb/MWh-gross for all combustion 

turbines without any size based subcategories. Emissions data 

from combined cycle facilities with heat input ratings of less 

than 850 MMBtu/h have demonstrated that this level is achievable 

for smaller combined facilities. The sixteen NGCC facilities 

evaluated using the Clean Air Markets data have heat input rates 

of less than or equal to 850 MMBtu/h and an average 12-month 

maximum CO2 emission rate of 952 lb/MWh-gross. Three of the 

facilities evaluated using the Clean Air Markets data had a 

maximum 12-operating month rolling average emissions rate equal 

to or greater than 1,000 lb CO2/MWh-gross. One of those 
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facilities had a maximum 12-operating-month rolling average 

emissions rate equal to or greater than 1,100 lb CO2/MWh-gross. 

In addition, the five facilities that commenced construction 

between 2007 and 2012 all have maximum 12-month emission rates 

of less than 950 lb CO2/MWh-gross. For larger units, twenty-five 

of the 314 combined cycle facilities with heat input ratings 

greater than 850 MMBtu/h had maximum 12-month average emission 

rates greater than 1,000 lb CO2/MWh. The analysis inherently 

includes multiple years of data and did not filter out periods 

of startup, shutdown, operation at intermediate load, or cycling 

when determining the maximum 12-operating month emission rate. 

The final standard includes a sufficient compliance margin to 

account for any performance degredation in the operation of 

these facilities. 

In addition, multiple technologies that can increase the 

performance of new combined cycle facilities are currently 

available. First, vendors continue to improve the single cycle 

efficiency of combustion turbines. The use of more efficient 

combustion turbine engines improves the overall efficiency of 

combined cycle facilities. In addition, existing smaller 

combined cycle facilities were likely designed using single or 

dual pressure heat recovery steam generators without a reheat 

cycle. New designs could incorporate three pressure steam 

generators with a reheat cycle to improve the overall efficiency 
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of the combined cycle facility. Additional technologies to 

reduce emission rates for new combustion turbines include CHP 

and integrated non-emitting technologies. 

The EPA reviewed the GHG limitations in recently issued 

construction permits for NGCC facilities. In total 31 major 

permits were identified with 39 discrete limits on GHG 

emissions. Eight of the limits were expressed as lbs/h or tons 

per year and were not included in the analysis. In addition, One 

CHP unit that generates electricity and supplies steam to a 

chemical plant was in the set with a limit of 1,362 lb CO2/MWh

based only on the gross electrical portion of output and does 

not account for the useful thermal output. Therefore, it was 

also not included in this analysis. Two of the permits did not 

clearly specify if the output based standard was on a gross or 

net basis and were therefore also excluded. The remaining 28

permit standards were expressed on a lb CO2/MWh or a heat rate 

basis that could be converted to a lb CO2/MWh basis. Eight permit 

limits were based on net output ranging from 774-936 lb CO2/MWhnet. The lowest emission limit was for a hybrid power plant with 

a solar component of heat input that could contribute up to 50 

MW. Twenty permit limits were based on gross output ranging from 

833-1,100 lb CO2/MWh-gross. Of these 28 permit limits, only one 

unit had a heat input capacity less than 1,500 MMBtu/h (366 

MMBtu/h); this unit also had the highest emission limit of 1,100 
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lb CO2/MWh. All permit limits were evaluated over an annual 

period. Most of these permits included an allowance for a design 

margin to reflect the possibility that the constructed facility 

will not be able to achieve the design heat rate; an allowance 

for efficiency losses due to combustion turbine degradation 

prior to maintenance overhauls; an allowance for the steam 

turbine system; and an allowance for the variability in 

operation of auxiliary plant equipment due to use over time. 

Typically, the sum of these allowances was in the range of 10 to 

13 percent. Limits typically considered whether the unit would 

be base load or load-following. Some permits limited the amount 

of No. 2 fuel oil that could be used as backup fuel and adjusted 

emission limits to account for this use. Startup and shutdown 

emissions were typically included in the annual average 

compliance calculation. 

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 
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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 U.S. Court of Appeals for the District of 

Columbia 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 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, 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 
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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. 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 

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 
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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.

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 
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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 

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 
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malfunctions is consistent with CAA section 111 and is a 

reasonable interpretation of the statute. 

In the 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.
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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 

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 
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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 

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.”).404 In light of NRDC, the EPA is not including 

a regulatory affirmative defense provision in this final rule. 

 

404 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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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 

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.405

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 as frequent as practicable while 

 

405 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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ensuring monitoring accuracy and stringency required under the 

program.

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 
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copy components, in accordance with sections 75.53(g) and (h). 

The electronic portion of the monitoring plan should be 

submitted to the EPA’s Clean Air Markets Division (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 section 75.20 and section 6 of 

Part 75, Appendix A within the 180-day window of time allotted 

under section 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 
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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 

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 section 

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 
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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 

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. 
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EGU owners or operators have the option to use backup monitoring 

systems, as provided in sections 75.10(e) and 75.20(d), to help 

meet this data capture requirement. This requirement is separate 

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 section 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 section 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-gross) 

emission standard, the initial performance test consists of the 
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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 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 section 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

This final rule specifies that compliance with the 1,400 lb 

CO2/MWh-gr emission limit is determined on a 12-operating-month 

rolling average basis, updated after each new operating month. 

For each 12-operating-month 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 

section 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.

E. Notification, Recordkeeping, and Reporting Requirements

This final rule requires an EGU owner or operator to comply 

with the applicable notification requirements in section 75.61, 

sections 60.7(a)(1) and (a)(3), and section 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 
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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 

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 2 years, after which the records can be maintained off-site. 

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 section 

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., 

oil-fired 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 
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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. 

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 
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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. 

Currently, ECMPS is not programmed to receive the 

additional information included in the report required under 

section 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. 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 

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 
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the Best Available Control Technology (BACT) requirement for 

greenhouse gases 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 

and existing and 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.

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 
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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 

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 
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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 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 

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 
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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 greenhouse 

gases would 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 
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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 at 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 

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 
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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 at 1488 (citing 75 FR 31582). 

Nevertheless, to ensure there would be no uncertainty as to this 

issue, the EPA proposed to adopt explicit language in sections 

60.46Da(j), 60.4315(b), and 60.5515 of the agency’s regulations. 

The 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 
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pollutant” to GHGs regulated under subparts Da, KKKK, and TTTT 

of part 60.

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 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 GHG 

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, 

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 
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application of PSD permitting requirements to Step 2 sources 

based on GHG emissions. The Court also recognized that, although 

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 sections 51.166(b)(48)(v) 

and 52.21(b)(49)(v) of the EPA’s regulations, but did not vacate 

sections 51.166(b)(48)(iv) or 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 

phase in that 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 
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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 sections 

51.166(b)(48)(iv) and 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 SER 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 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 the SER

rule, it will then provide a framework that states may use when 

updating their SIPs consistent with the Supreme Court decision. 
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While the GHG SER rulemaking 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 

sections 60.46Da(j), 60.4315(b), and 60.5515. 

The EPA has evaluated these provisions 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 

alone, the limitation in sections 51.166(b)(48)(iv) and 

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 the EPA proposed for 

sections 60.46Da(j), 60.4315(b), and 60.5515 will continue to be 

effective at avoiding this result after the judicial actions 
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described above and the adoption of this final rule. The 

provisions in part 60 reference sections 51.166(b)(48) and 

52.21(b)(49) of the EPA’s regulations. However, the courts have 

now vacated sections 51.166(b)(48)(v) and 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 in 60.46Da(j),

60.4315(b), and 60.5515 will not incorporate the vacated parts 

of sections 51.166(b)(48) and 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 sections 60.46Da(j), 60.4315(b), 

and 60.5515 without change.

As to the concern expressed by some commenters that 

revisions to part 60 alone are not sufficient, the GHG SER 

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 
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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 sections 

60.46Da(j), 60.4315(b), and 60.5515 to other subparts of part 

60. 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 section 51.166 at this time solely to address the 

implications of regulating GHGs under CAA section 111. 

The EPA understands that many commenters expressed 

concerned that PSD SIPs would also have to be amended to address 

the implications of regulating GHGs under CAA section 111. 
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However, the language in 60.46Da(j), 60.4315(b), and 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 at 31522. 

Moreover, it is more likely that states would need to 

consider a SIP revision if the EPA were to revise section 51.166 

in this rule. Revisions to 51.166 can trigger requirements for 

states to revise their PSD program provisions under section 

51.166(a)(6). 

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 consolidate its revisions 

to 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 
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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 

believe such action will be necessary in any state after the 

Supreme Court decision and our action in this rule to adopt the 

proposed part 60 provisions in this final rule 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 
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applicability can be found in 40 CFR 51 and 52 as discussed 

briefly in the preceding section. 

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, 

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, p. 20-21 (March 2011) (“GHG Permitting Guidance”). Thus, 
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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 is established by the EPA through an applicable NSPS 

(i.e. the BACT floor) does not bar a permitting agency from 

justifying a more stringent standard as BACT. 

In the proposed rule, the EPA discussed how this rule may 

relate to determination of BACT for new and existing EGUs that 

require PSD permits. 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 both a new, greenfield EGU 

facility or an existing facility that wants to add a new EGU in 

order to add or replace capacity. While this latter scenario is 

considered a “new affected facility” under the NSPS, it may also 

be considered a “modification” of an existing stationary source 

under PSD. Thus, the new source NSPS requirements could apply to 

a modification, as that term is defined under PSD. 
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In addition, this NSPS will apply to modified or 

reconstructed sources as those terms are defined under part 60. 

It is important to recognize that 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 

modification or reconstruction requirements, a physical change 

must increase the maximum potential 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 the specified emission threshold in order to be 

subject to PSD requirements. This emission calculation considers 

the unit’s past annual emission 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, this NSPS could establish 

a BACT floor for sources that are modifying an existing EGU and 

their emissions make them subject to PSD.
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In the preamble to the proposed rule, 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 permitting a 

modified or reconstructed EGUs or non-EGU sources. 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.406 This 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.

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 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 

should be the basis for BSER) rather than examining whether an 

 

406

 U.S. EPA, PSD and Title V Permitting Guidance for Greenhouse 

Gases, p. 24 (March 2011).
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NSPS should establish the BACT floor for applicable sources, 

which is a natural consequence of setting an NSPS under the 

terms of the CAA. 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. In addition, to date the EPA has not issued a PSD 

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 with setting a BSER of partial 

CCS in this NSPS. Although some permitting authorities may have 

determined that CCS is not technologically feasible or 

economically achievable for a gas-fired EGU, because of the 

case-by-case nature of the analysis, it does not automatically 

follow that the same conclusion is appropriate for a solid fuelfired EGU. Furthermore, PSD permitting requirements first 

applied to greenhouse gases in January 2011 and more information 
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about GHG control technology has been gained in this four-and-ahalf year period. 

Additionally, if a state was processing a permit 

application for a solid fuel-fired EGU and CCS was not proposed

as BACT (or not even considered as a possible 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 approved state implementation plan, the state has 

primacy over their permitting actions and discretion to 

interpret their approved rules and 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. Furthermore, if 

the EPA does not adversely comment on a certain permit or BACT 

determination, it does not necessarily imply EPA endorsement of 

the proposed permit or determination.

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 
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guidance -- it does not contain any final determination of BACT 

for any source. Furthermore, we disagree with the commenters’ 

characterization of the content of the GHG Permitting Guidance. 

The guidance specifically states “[f]or the purposes of a BACT 

analysis for GHGs, 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 

stand by its position on the availability of CCS in this 

context, as expressed in the GHG Permitting Guidance.

The Guidance continues on to discuss case-specific 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 challenges when it 
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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. Nothing in the guidance is inconsistent with 

agency’s present position that CCS is adequately demonstrated 

for the types of sources covered by this rule, 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 required 

"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 

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 was 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 
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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 at 1489-90. The 

relevant issue for title V purposes was, in essence, whether 

promulgation of CAA section 111 requirements for GHGs would 

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 at 1489-90 (quoting 75 FR 31,583). Under the 
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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 

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 at 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 
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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 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 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 EPA imposing a 

requirement that stationary sources obtain a title V permit 
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solely because such sources emit or have the potential to emit 

GHGs above the applicable major source thresholds.407

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 

above on which a title V permit may be required or the 

applicable requirements that must be addressed in title V 

permits.408 Consistent with the proposal, the EPA has concluded 

 

407 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.

408 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 
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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 today 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 

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, 

 

Court’s Decision in Utility Regulatory Group v. Environmental 

Protection Agency (July 24, 2014) at 5.
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local and tribal permitting authorities409 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 at 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. at 1490. The EPA did 

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 

 

409 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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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 

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 
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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 

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 
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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 at 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. at 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 calculation)” in 40 CFR 71.2.410 See NSPS 

preamble at 1493, 1495. 

 

410 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.”
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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,411 “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 at 1494. 

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. 

 

411 Burden is the hours of staff time necessary to perform a 

task.
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See 79 FR at 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.412 See NSPS proposal at 

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, the cost of permitting for any 

particular source may be accounted for adequately without 

charging any additional fees related to GHGs. Id. at 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 

 

412 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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purposes would be considered to be “GHGs,” (as defined in 40 CFR 

70.2 and 71.2),413 rather than solely CO2, which would be 

regulated under the section 111 standards and implemented 

through the EGU GHG NSPS. Id. at 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. at 1490, 1517, 1518.

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 

 

413

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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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 

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 
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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.

a. The GHG exemption.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 
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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 

of GHG permitting414 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 

 

414 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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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 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 
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local permitting authorities supported finalizing no adjustment 

and a few others asked for flexibility to set fee adjustments 

not proposed by 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 

pollutants, which are not directly related to the costs of GHG 

permitting.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 
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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. 

States that implement the presumptive minimum approach will 

need to follow the final rule’s option 1 approach.415 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.

 

415 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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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 

assessment of the significance of the changes. Certain changes, 

such as switching from the presumptive minimum method to a 

detailed accounting fee demonstration 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)416, 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 

 

416 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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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. 

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 
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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 

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.”417 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 

 

417 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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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.

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.418 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 

 

418 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 at 1494.
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permitting should be minimal because few applicable requirements 

will apply to GHGs. As stated earlier in this notice, EPA’s cost 

estimate for the proposal concerned the incremental costs of GHG 

permitting for any source, not just those that would 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.
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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 

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 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 
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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 

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.419

 

419 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 
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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 

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.

 

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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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 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 prt 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 GHG emission standards for the 

affected sources (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 
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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 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
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Fossil fuel-fired EGUs are, or potentially will be, 

impacted by several other recently finalized or proposed EPA 

rules.420 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 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 

 

420 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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air pollutants, also known as hazardous air pollutants or air 

toxics, are known to cause, or suspected of causing, damage 

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.

2. Cross-State Air Pollution Rule (CSAPR)

The CSAPR requires states to take action to improve air 

quality by reducing SO2 and nitrogen oxide (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 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 
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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.421 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 

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) 

 

421 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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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 

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 

simultaneously with this rule. 

5. Steam Electric Effluent Limitation Guidelines and Standards 

(SE ELG Rule)
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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 

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 
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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 fossil fuel-fired steam 

generating units that can be met by capturing and storing 

approximately 20 percent of the CO2 produced from the facility or 

by utilizing other technologies such as natural 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 unitspecific 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 
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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.

422

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 

 

422 It should be noted that regulatory obligations imposed upon 

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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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.

XII. 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-XX-YYY, June 2015) (RIA), 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 
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of newly constructed EGUs by 2022.423 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 the 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 

today. 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 

 

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

model year of 2020.
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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 

modified or reconstructed EGUs in the period of analysis. 

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 

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 designated critical habitat. Section 7(a)(2) of the ESA 

requires federal agencies, in consultation with the U.S. Fish 

and Wildlife Service (FWS) and/or the National Marine Fisheries 

Service, 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. 
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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 

environmental baseline. 50 CFR 402.02. Indirect effects are 

those that are caused by the action, later in time, and are 

reasonably certain to occur. Id. To trigger a consultation 

requirement, there must thus be a causal connection between the 

federal action, the effect in question, and the listed species, 

and the effect must be reasonably certain to occur.

 The EPA has considered the 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 species or 

designated critical habitat for purposes of ESA section 7(a)(2) 

consultation. 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). These reductions are projected to be 

minor. Although the final rule imposes substantial controls on 

CO2 emissions, we project few if any new fossil fuel-fired steam 

generating units to be built. Emissions reductions from turbines 

are likewise projected to be minimal. With respect to the 
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projected GHG emission reductions, the EPA does not believe that 

such 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 in the context of 

listing the polar bear as a 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.329 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). 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 question330 and, based on air 

quality modeling of potential environmental effects, concluded 

that “EPA knows of no modeling tool which can link these small, 

time-attenuated changes in global metrics to particular effects 

on listed species in particular areas. Extrapolating from global 
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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 CO 2 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).

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 

choose to build new EGUs that comply with the regulatory 
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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 reconstructed or 

modified EGUs 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 

reconstructed or modified EGUs 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 

plant utilize partial CCS to meet the final standard of 

performance (i.e., approximately 20 percent capture), the 

increased water use will not be significant. The EPA is unaware 

of any solid waste impact resulting from this rule.

E. What are the compliance costs?

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 
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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. 

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 modified or reconstructed EGUs 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 
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U.S. economy.

As previously stated, the EPA anticipates few units will 

trigger the 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?

There are no direct monetized climate benefits in terms of 

CO2 emission reductions associated with these standards of 

performance. However, by clarifying that in the future, newly 

constructed coal-fired power plants will be required to meet a 

particular performance standard, this rule provides a path 

forward for new coal-fired generation and the deployment of CCS.

It ensures that new EGUs, whether gas or coal-fired, will meet 

standards for CO2 control into the future.

As also previously stated, the EPA anticipates few units 

will trigger the 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.

XII. 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.

A. Executive Order 12866, Regulatory Planning and Review, and 
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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-XX-YYY, June 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

(electric utility steam generating units and natural gas-fired 
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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 modified or reconstructed EGUs 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.

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 
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prepared has been assigned EPA ICR number XX. 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 2506.03). 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. 

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.
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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 

natural gas-fired 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 

2060-0629, respectively. Apart from certain reporting costs 

based on requirements in the NSPS General Provisions (40 CFR 

part 60, subpart A), which are mandatory for all 

owners/operators subject to CAA section 111 national emission 
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standards, 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 17 affected newly 

constructed natural gas-fired stationary 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 natural gas-fired 

stationary combustion turbines). As previously stated, the EPA 

expects few modified or reconstructed EGUs in the period of 

analysis. Specifically, the EPA believes it unlikely that fossil 
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fuel-fired electric utility steam generating units or natural 

gas-fired 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 sources 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, which are mandatory for all owners/operators 

subject to CAA section 111 national emission standards, 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 

provisions, if an EGU were to modify or reconstruct during the 
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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 $2,665 and 

32 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 $32,886 and 

395 labor hours. There are no annualized capital costs or O&M 

costs associated with burden for newly constructed EGUs. Average 

burden hours per response are estimated to be 8 hours. The total 

number of respondents over the 3-year ICR period is estimated to 

be 37.

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 

significant economic impact on a substantial number of small 
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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. 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 Reconstructed Stationary 

Sources: Electric Utility Generating Units” (EPA-452/R-XX-YYY, 
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June 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 modified fossil fuel-fired electric 

utility steam generating units or natural gas-fired stationary 

combustion turbines 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 

anticipate that the rule would impose significant costs on those 

sources, including any that are owned by small entities. (See 
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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-XX-YYY, June 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” (EPA452/R-XX-YYY, June 2015) for further discussion of 

sensitivities.)
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As previously stated, the EPA expects few modified or 

reconstructed fossil fuel-fired electric utility steam 

generating units or natural gas-fired stationary combustion 

turbines 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-XX-YYY, 

June 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 

governments is $100 million annually and, as stated above, we

have concluded that the final action will not result in 
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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 

modified or reconstructed fossil fuel-fired electric utility 

steam generating units or natural gas-fired stationary 

combustion turbines 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 modified or reconstructed fossil fuel-fired electric 

utility steam generating units or natural gas-fired stationary 

combustion turbines in the period of analysis. We, therefore, 

anticipate that the final rule will impose minimal compliance 

costs.
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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 modified 

or reconstructed EGUs 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.

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 
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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 

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. 
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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).

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 
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children. Accordingly, the agency has evaluated the 

environmental health and welfare effects of climate change on 

children. 

CO2 is a potent greenhouse gas that contributes to climate 

change and is emitted in significant quantities by fossil fuelfired power plants. The EPA believes that the CO2 emission 

reductions resulting from implementation of these final 

guidelines, as well as substantial ozone and PM2.5 emission 

reductions as a co-benefit, will further improve 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 
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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 

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. 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 modified or reconstructed fossil 

fuel-fired electric utility steam generating units or natural 

gas-fired stationary combustion turbines 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.
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I. National Technology Transfer and Advancement Act 

This final action involves technical standards. The 

following voluntary consensus standards are used in the final 

rule: American Society for Testing and Materials (ASTM) Methods 

D388-12 (Standard Classification of Coals by Rank), D396-13c 

(Standard Specification for Fuel Oils), D975-14 (Standard 

Specification for Diesel Fuel Oils), D3699-13b (Standard 

Specification for Kerosene), D6751-12 (Standard Specification 

for Biodiesel Fuel Blend Stock (B100) for Middle Distillate 

Fuels), D7467-13 (Standard Specification for Diesel Fuel Oil, 

Biodiesel Blend (B6 to B20)), and American National Standards 

Institute (ANSI) Standard C12.20 (American National Standard for 

Electricity Meters - 0.2 and 0.5 Accuracy Classes). The rule 

also requires use of Appendices A, B, D, F and G to 40 CFR part 

75; 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 
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appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies and activities 

on minority populations and low-income populations in the 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. These 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 F and G, above, where EPA discusses 

Consultation and Coordination with Tribal Governments and 
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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.

Strong scientific evidence that the potential impacts of 

climate change raise environmental justice issues is found 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, summarized in the record for the Endangerment 

Finding. Their conclusions include 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 on established reservations that are restricted to 

reservation boundaries and therefore have limited relocation 

options. 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. 

Southwest native cultures are especially vulnerable to 

water quality and availability impacts. Native Alaskan 

communities are likely to experience disruptive impacts, 
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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.424 The new assessment 

literature provides more detailed findings regarding these 

populations’ vulnerabilities and projected impacts they may 

experience. In addition, the most recent assessment literature 

provides new information on how some communities of color may be 

uniquely vulnerable to climate change health impacts in the 

 

424 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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United States. These studies 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, the studies 

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 

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 natural gas-fired 

stationary combustion turbines by establishing national emission 

standards for CO2.
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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 modified or reconstructed fossil fuel-fired electric utility 

steam generating units or natural gas-fired stationary 

combustion turbines 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.

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 
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Comptroller General of the United States. This action is not a 

“major rule” as defined by 5 U.S.C. 804(2).

XIII. 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)).
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Standards of Performance for Greenhouse Gas Emissions from New, 

Modified, and Reconstructed Stationary Sources: Electric Utility 

Generating Units

Page 536 of 589

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
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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. Part 60 is amended by adding subpart TTTT to read as follows:

Subpart TTTT Standards of Performance for Greenhouse Gas Emissions for 

Electric Utility Generating Units 

Sec.

Applicability

§ 60.5508 What is the purpose of this subpart?

§ 60.5509 Am I subject to this subpart?

Emission Standards

§ 60.5515 Which greenhouse gases are regulated by this subpart?

§ 60.5520 What CO2 emissions standard must I meet?

General Compliance Requirements
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§ 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?
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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 modification or 

reconstruction 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. 

(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)(9) of this section.
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(1) Your EGU is a steam generating unit or IGCC that is currently 

and always has been subject to a federally enforceable permit limiting 

net-electric sales to one-third or less of its potential electric 

output or 219,000 MWh or less on an annual basis.

(2) Your EGU is capable of combusting 90% or more non-fossil fuel 

and subject to a federally enforceable permit limiting fossil fuel use 

to 10% or less of the annual capacity factor.

(3) Your EGU is a combined heat and power unit that is subject to 

a federally enforceable permit limiting annual net-electric sales to 

the design efficiency times the potential electric output or 219,000 

MWh (whichever is greater) or less.

(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 unit that is 

subject to subpart Eb of this part.

(6) Your EGU is a commercial or industrial solid waste 

incineration unit that is subject to subpart CCCC of this part.

(7) Modified units that conduct modifications resulting in a 

potential hourly increase in CO2 emissions (mass per hour) of 10 

percent or less.
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(8) Your EGU is a stationary combustion turbine that is subject 

to a federally enforceable permit limiting annual net-electric sales 

to the design efficiency times the potential electric output or less 

as net-electrical sales.

(9) Your stationary combustion turbine is not capable of 

combusting natural gas (e.g., not connected to a natural gas 

pipeline).

Emission Standards

§ 60.5515 Which greenhouse gases are regulated by this subpart?

(a) The greenhouse gas regulated by this subpart is carbon 

dioxide (CO2).

(b) PSD and Title V Thresholds for Greenhouse Gases.

(1) For the purposes of § 51.166(b)(49)(ii) of this 

chapter, with respect to GHG emissions from affected EGUs, 

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 § 52.21(b)(50)(ii) of this 

chapter, with respect to GHG emissions from affected 

facilities, the “pollutant that is subject to the standard 
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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 § 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 § 70.2 

of this chapter.

(4) For the purposes of § 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 § 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) and (c) of this section,

as applicable. 

(b) Except as specified in paragraph (c) of the section, you must 

comply with the applicable gross energy output standard and your 

operating permit must include monitoring, recordkeeping, and reporting 
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methodologies based on the applicable gross 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 “gross energy 

output.”

(c) As an alternate to meeting the requirements in paragraph (b) 

of this section, an owner or operator may petition the Administrator 

in writing to comply with the alternate applicable net energy output 

standard. If the Administrator grants the petition, the source will 

beginning on the date the Administrator grants the petition have to

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.

General Compliance Requirements

§ 60.5525 What are my general requirements for complying with this 

subpart?

Compliance with the applicable CO2 emission standard of this 

subpart shall be determined on a 12-operating month rolling average 

basis. See Tables 1-2 for the applicable CO2 emission standards. 

(a) You must be in compliance with the emission standards in this 
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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.

(b) At all times you must operate and maintain each affected EGU, 

including associated equipment and monitoring equipment, in a manner

consistent with safety and good air pollution control practice. The 

Administrator will determine if you are using consistent operation and 

maintenance procedures based on information available to the 

Administrator that may include, but is not limited to, fuel use 

records, monitoring results, review of operation and maintenance 

procedures and records, review of reports required by this subpart, 

and inspection of the EGU.

(c) Within 30 days after the end of the initial compliance period 

(i.e., no more than 30 days after the first 12-operating month 

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-operating month compliance period shall be determined 

as follows: 
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(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 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) 
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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) You must prepare a monitoring plan to quantify the hourly CO2

mass emission rate (tons/hr), 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 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.
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(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, 

operate, maintain, and calibrate a continuous moisture 

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

(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 
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gas flow rate data.

(4) You must select an appropriate reference method to setup 

(characterize) the flow monitor and to perform the on-going 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. 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/hr), 

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/hr values and EGU (or stack) operating 
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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. 

(1) 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/hr). You may determine site-specific carbon-based 

F-factors (Fc) using Equation F-7b in section 3.3.6 of appendix F to 

part 75 of this chapter, and you may use these Fc values in the 

emissions calculations instead of using the default Fc values in the 

Equation G-4 nomenclature.

(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 it to 
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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) 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.

(d) Consistent with § 60.5520, you must install, calibrate, 

maintain, and operate a sufficient number of watt meters to 

continuously measure and record the hourly gross electric output 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. 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.

(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 
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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 

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 
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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, to demonstrate compliance 

with the applicable CO2 emission standard in Table 1 or 2 of this 

subpart, for the initial and each 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 (kg/MWh). You must use the hourly CO2

mass emissions and generation load data from §60.5535 in the 

calculations.

(1) Each compliance period shall include only “valid 

operating hours” in the compliance period, i.e., operating hours 

for which: 
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(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 

(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

(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

(iii) The total gross or net energy output (Pgross/net) 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) 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 emissions, you must determine Pgross/net (the 
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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.

/ = 

() + () + () − ()

T

+ [ () + () + () ]
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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.

(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.
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(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.

T = Electric Transmission and Distribution Factor.

T = 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 percent of the total 

gross or net energy output consists of useful thermal 

output on a 12-operating month rolling average basis.

T = 1.0 for all other affected EGUs.

(ii) If applicable to your affected EGU, you must calculate (Pt)PS

using the following equation:

() =

 × 

3.6 × 10
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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, as applicable) 

in Joules per kilogram (J/kg) (or Btu/lb).

3.6 x 109 = Conversion factor (J/MWh) (or 3.413 x 106 Btu/MWh).

(6) In accordance with § 60.5520, 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.

(7) 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) of 

this section. Round off the result 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 
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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 or 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 § 

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 
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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 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);
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(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 energy 

output sold to an electric grid 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 
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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 

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. 
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(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 electrical 

generation data on that date. Otherwise, emissions data 

reporting shall begin on the date that the Client Tool is first 

able to receive and process net generation data. 

(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 
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(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) 

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.

(e) 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.

§ 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 § 
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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.

(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
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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), 

(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-operating 

month 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.
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(e) You must keep records of the calculations you performed to 

determine the percentage of valid CO2 mass emission rates in each 

compliance period. 

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

assess compliance with each applicable CO2 mass emissions standard in 

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. You may 

maintain the records off site and electronically for the remaining 

year(s) as required by this subpart.

Other Requirements and Information

§ 60.5570 What parts of the General Provisions apply to my affected 

EGU?
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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?

(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 
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reporting.

(5) Performance test and data reduction waivers under § 

60.8(b).

§ 60.5580 What definitions apply to this subpart?

As used in this subpart, all terms not defined herein will have 

the meaning given them in the Clean Air Act and in subpart A (General 

Provisions of this part).

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, baseload 

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 solventrefined 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.
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Coal refuse means waste products of coal mining, physical 

coal cleaning, and coal preparation operations (e.g. culm, gob, 

etc.) containing coal, matrix material, clay, and other organic 

and inorganic material.

Combined cycle 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 thermal output) on a higher heating value 

basis of the EGU at the base load rating and ISO conditions.

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 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 § 
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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).

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), combustion turbine(s), 

and gas expander(s)) plus 100 percent of the useful thermal output.

(2) For electric utility 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 
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direct mechanical output and 20.0 percent of the total gross energy 

output consists of useful thermal output on a 12-operaitng 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 a 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 

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.
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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. In 

addition, natural gas contains 20.0 grains or less of total sulfur per 

100 standard cubic feet. Finally, natural gas does not include the 

following gaseous fuels: landfill gas, digester gas, refinery gas, 

sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven 

gas, or any gaseous fuel produced in a process which might result in 

highly variable sulfur content or heating value.

Net-electric sales means 

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

system minus purchased power; or
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(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 grid 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 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
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(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.

Petroleum means crude oil or a fuel derived from crude 

oil, including, but not limited to, distillate and residual 

oil.

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.

Potential electric output means 33 percent or the design 

efficiency on a net output basis 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 
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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). 

Solid fuel means any fuel that has a definite shape and volume, 

has no tendency to flow or disperse under moderate stress, and is not 

liquid or gaseous at ISO conditions. This includes, but is not limited 

to, coal, biomass, and pulverized solid fuels. 

Stationary combustion turbine means all equipment, including but 

not limited to the 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 sub-components comprising any simple cycle stationary 

combustion turbine, any combined cycle combustion turbine, and any 

combined heat and power combustion turbine based system plus any 

integrated equipment that provides electricity or useful thermal 

output to the combustion turbine engine, heat recovery system or 

auxiliary equipment. Stationary means that the combustion turbine is 

not self-propelled or intended to be propelled while performing its 

function. It may, however, be mounted on a vehicle for portability. If 

a stationary combustion turbine burns any solid fuel directly it is 

considered a steam generating unit.

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

used for combusting fuel and producing steam (nuclear steam generators 

are not included) plus any integrated equipment that provides 
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electricity or useful thermal output to the affected EGU(s) or 

auxiliary equipment.

Useful thermal output means the thermal energy made available for 

use in any heating application (e.g., steam delivered to an industrial 

process for a heating application, including thermal cooling 

applications) that is not used for electric generation, mechanical 

output at the affected 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 the energy in the condensate and subtract 

that energy relative to SATP conditions from the measured thermal 

output. 

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 
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reported under this subpart; for on-going 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 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.
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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 (net energy outputbased standards are only applicable to affected EGUs subject to a 

federally enforceable permit limiting GHG emissions on a net energy 

output basis)

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

Affected EGU CO2 Emission Standard

Newly constructed steam 

generating unit or integrated 

gasification combined cycle 

(IGCC) EGU

640 kg CO2/MWh of gross energy 

output (1,400 lb CO2/MWh)

Reconstructed steam generating 

unit or IGCC EGU 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 EGU 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 or IGCC 

unit

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.
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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 or Modification after June 

18, 2014

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

Affected EGU CO2 Emission Standard425

Newly constructed, reconstructed, 

or modified stationary combustion 

turbine 

450 kg of CO2 per MWh of gross 

energy output (1,000 lb CO2/MWh); 

or

490 kilograms (kg) of CO2 per 

megawatt-hour (MWh) of net energy 

output (1,080 lb/MWh) 

 

425 See procedures for establishing and revising the compliance option under § 60.5520.
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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
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§ 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 

§ 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.
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PART 70— STATE OPERATING PERMIT PROGRAMS

3. The authority citation for part 70 continues to read as 

follows:

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

4. 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.

* * * * *

5. 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.

* * * * *
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(b) * * *

(2)(i) The Administrator will presume that the fee schedule 

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) 43
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GHG evaluation for a modification or related 

permit action

GHG evaluation at permit renewal

7

10

* * * * *

PART 71— FEDERAL OPERATING PERMIT PROGRAMS

6. The authority citation for part 71 continues to read as 

follows:

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

7. 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.

* * * * *

8. Section 71.9 is amended by:
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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.

* * * * *

(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 
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calculation) emitted from the source, including fugitive 

emissions; and 

(B) Any GHG fee adjustment required under paragraph (c)(8) 

of this section.

* * * * *

(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 
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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 

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: 
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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

9. 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

10. 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
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(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.

* * * * *

(d) Facilities subject to § 98.426(h) must retain records of CO2

in metric tons that is transferred to each subpart RR facility.